CANADIAN NATURAL RESOURCES LIMITED
(Registrant)
|
|||
Date: August 11, 2015
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By:
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/s/ B. E. McGrath | |
B. E. McGRATH | |||
Corporate Secretary | |||
Three Months Ended
|
Six Months Ended
|
||||||||||||||||||||
($ Millions, except per common share amounts)
|
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014
|
||||||||||||||||
Net earnings (loss)
|
$
|
(405
|
)
|
$
|
(252
|
)
|
$
|
1,070
|
$
|
(657
|
)
|
$
|
1,692
|
||||||||
Per common share |
– basic
|
$
|
(0.37
|
)
|
$
|
(0.23
|
)
|
$
|
0.98
|
$
|
(0.60
|
)
|
$
|
1.55
|
|||||||
– diluted
|
$
|
(0.37
|
)
|
$
|
(0.23
|
)
|
$
|
0.97
|
$
|
(0.60
|
)
|
$
|
1.54
|
||||||||
Adjusted net earnings from operations (1)
|
$
|
178
|
$
|
21
|
$
|
1,150
|
$
|
199
|
$
|
2,071
|
|||||||||||
Per common share |
– basic
|
$
|
0.16
|
$
|
0.02
|
$
|
1.05
|
$
|
0.18
|
$
|
1.90
|
||||||||||
– diluted
|
$
|
0.16
|
$
|
0.02
|
$
|
1.04
|
$
|
0.18
|
$
|
1.89
|
|||||||||||
Cash flow from operations (2)
|
$
|
1,503
|
$
|
1,370
|
$
|
2,633
|
$
|
2,873
|
$
|
4,779
|
|||||||||||
Per common share |
– basic
|
$
|
1.38
|
$
|
1.25
|
$
|
2.41
|
$
|
2.63
|
$
|
4.38
|
||||||||||
– diluted
|
$
|
1.37
|
$
|
1.25
|
$
|
2.39
|
$
|
2.62
|
$
|
4.36
|
|||||||||||
Capital expenditures, net of dispositions
|
$
|
1,297
|
$
|
1,412
|
$
|
5,456
|
$
|
2,709
|
$
|
7,349
|
|||||||||||
Daily production, before royalties
|
|||||||||||||||||||||
Natural gas (MMcf/d)
|
1,779
|
1,771
|
1,634
|
1,775
|
1,406
|
||||||||||||||||
Crude oil and NGLs (bbl/d)
|
509,047
|
602,809
|
545,169
|
555,669
|
517,134
|
||||||||||||||||
Equivalent production (BOE/d) (3)
|
805,547
|
898,053
|
817,471
|
851,545
|
751,426
|
(1) | Adjusted net earnings from operations is a non-GAAP measure that the Company utilizes to evaluate its performance. The derivation of this measure is discussed in the Management’s Discussion and Analysis (“MD&A”). |
(2) | Cash flow from operations is a non-GAAP measure that the Company considers key as it demonstrates the Company’s ability to fund capital reinvestment and debt repayment. The derivation of this measure is discussed in the MD&A. |
(3) | A barrel of oil equivalent (“BOE”) is derived by converting six thousand cubic feet (“Mcf”) of natural gas to one barrel (“bbl”) of crude oil (6 Mcf:1 bbl). This conversion may be misleading, particularly if used in isolation, since the 6 Mcf:1 bbl ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. In comparing the value ratio using current crude oil prices relative to natural gas prices, the 6 Mcf:1 bbl conversion ratio may be misleading as an indication of value. |
§ | Canadian Natural’s 2015 second quarter crude oil and NGL production volumes averaged 509,047 bbl/d, and natural gas volumes reached record quarterly levels of 1,779 MMcf/d. |
§ | Operations during Q2/15 were solid as the Company’s large, balanced and diverse asset base continues to support the transition to a longer life and lower decline asset base. Q2/15 operational highlights include: |
— | Pelican Lake production volumes increased in the second quarter to record levels of 52,015 bbl/d, 5% higher than Q2/14 levels and 2% higher than Q1/15 levels. This leading edge polymer flood continues to perform with increasing production volumes and decreasing operating costs despite no drilling activity since Q3/14. Canadian Natural leverages innovation and technology to create value through strong netbacks and robust economic returns. |
— | Operations at Septimus, Canadian Natural’s liquids-rich Montney natural gas play in British Columbia, continue to perform above expectations, with industry leading quarterly operating costs of approximately $0.18/Mcfe in Q2/15. |
— | Total Offshore Africa quarterly crude oil production in Q2/15 averaged 17,070 bbl/d, an increase of 30% over Q2/14 levels and an increase of 29% over Q1/15 levels. The infill drilling programs at the Espoir and Baobab fields in Côte d’Ivoire continue to be successfully executed with results exceeding expectations. |
2
|
Canadian Natural Resources Limited
|
– | To date, 3 gross wells have been drilled at Espoir, adding net production of approximately 4,500 bbl/d. Espoir is targeted to add overall net production volumes of 5,900 bbl/d through a 10 gross well program which includes 4 water injection wells (5.9 net well program) and is currently tracking below sanctioned costs. |
– | To date, Canadian Natural drilled 1 gross well at Baobab, adding net production volumes of approximately 2,000 bbl/d. Production from the second gross well is targeted to come on stream in the third quarter of 2015. Baobab is targeted to add overall net production volumes of 11,000 bbl/d through a 6 gross well program (3.4 net well program), which is currently tracking below sanctioned costs. |
— | Thermal operations were temporarily interrupted from late May to early June as a result of Northeastern Alberta forest fires. Employees were safely evacuated and only minor facility damage occurred. Total quarterly production volumes were reduced as a result of the related shut-down at Primrose and production curtailment at Kirby South. |
— | The Company continues to progress the low pressure steamflood operations at Primrose East Area 1 and the low pressure cyclic steam stimulation (“CSS”) operations at Primrose East Area 2. Operations at Primrose East are exceeding expectations, and due to the cyclic nature of operations at Primrose East Area 2, current production volumes are ranging from 15,000 bbl/d to 20,000 bbl/d. |
— | At Horizon Oil Sands (“Horizon”), the full maintenance turnaround originally scheduled in Q3/15 was deferred to 2016 to capture opportunities for production optimization of Phase 2B. During Q2/15, the Company planned a 10 day turnaround focusing on critical activities. The turnaround was extended from 10 days to 15 days to address necessary found work and the start-up of operations was slightly slower than expected. As a result, production volumes were lower than the Q2/15 guidance range. The Company targets strong production volumes going forward with Q3/15 production volumes targeted to range from 124,000 bbl/d to 131,000 bbl/d. 2015 annual production guidance remains unchanged from 121,000 bbl/d to 131,000 bbl/d. |
— | Due to Canadian Natural’s enhanced focus on operating efficiencies, the 2015 annual operating cost guidance range for Horizon has been further reduced from $31.00/bbl to $34.00/bbl to $30.00/bbl to $33.00/bbl. |
§ | Canadian Natural continues to execute capital discipline by proactively managing its drilling programs. As a result of the decrease in commodity pricing and other external events, the Company’s drilling activity consisted of just 13 net wells in Q2/15 compared to 191 net wells in Q2/14, a 93% reduction year over year. |
§ | Canadian Natural remains committed to its effective and efficient operations, with an enhanced focus on cost optimization. During the second quarter, the Company achieved strong operating cost reductions in the following areas: |
Q2/15
|
Q2/14
|
Year-over-Year
Percent Reduction |
||||||||||
North America Light Crude Oil and NGLs ($/bbl)
|
$
|
15.29
|
$
|
17.56
|
13%
|
|
||||||
Pelican Lake Heavy Crude Oil ($/bbl)
|
$
|
6.98
|
$
|
8.92
|
22%
|
|
||||||
Primary Heavy Crude Oil ($/bbl)
|
$
|
14.92
|
$
|
17.61
|
15%
|
|
||||||
Horizon Oil Sands Mining and Upgrading ($/bbl) (1)
|
$
|
29.25
|
$
|
36.61
|
20%
|
|
||||||
North Sea Light Crude Oil ($/bbl)
|
$
|
60.61
|
$
|
79.21
|
23%
|
|
||||||
Offshore Africa Light Crude Oil ($/bbl)
|
$
|
43.88
|
$
|
58.41
|
25%
|
|
||||||
North America Natural Gas ($/Mcf)
|
$
|
1.28
|
$
|
1.48
|
14%
|
|
(1) | Horizon Q2/15 operating costs adjusted to reflect impact of the June 2015 maintenance turnaround. |
§ | Given the cyclical nature of Primrose operations and the continued ramp up of production volumes at Kirby South, quarterly cost comparison year over year is not indicative of performance. However, on an annual basis, with a continued focus on effective and efficient operations, thermal operating costs are targeted to reduce by 13%. |
§ | In addition to the operating cost efficiencies achieved during the quarter, Canadian Natural continues to attain capital cost savings and has lowered its capital spending program by an additional $245 million from $5,745 million to $5,500 million. This reduction is a result of the Company’s ability to optimize its execution strategy, enhance productivity, right scope projects, leverage technology, and achieve lower energy and material costs. |
§ | Canadian Natural generated cash flow from operations of approximately $1.5 billion in Q2/15 compared to approximately $2.6 billion in Q2/14 and $1.4 billion in Q1/15. The decrease in Q2/15 from Q2/14 primarily reflects lower benchmark pricing partially offset by reduced operating costs. |
Canadian Natural Resources Limited
|
3
|
§ | The Company incurred a net loss in Q2/15 of $405 million, compared to net earnings of $1,070 million in Q2/14 and a net loss of $252 million in Q1/15. The net loss in Q2/15 was primarily a result of the 20% increase in the Alberta provincial corporate income tax rate from 10% to 12%, increasing Canadian Natural’s deferred income tax liability by $579 million. Adjusted net earnings from operations for Q2/15 were $178 million, compared to adjusted net earnings of $1,150 million in Q2/14 and $21 million in Q1/15. Changes in adjusted net earnings largely reflect the changes in cash flow. |
§ | During Q2/15, Canadian Natural’s $1,500 million revolving syndicated credit facility was increased to $2,425 million and the maturity date was extended to June 2019 from June 2016. The Company’s $3,000 million revolving syndicated credit facility was reduced to $2,425 million and the maturity date was extended to June 2020 from June 2017. As a result, the Company’s available liquidity increased by $350 million, ending the quarter at approximately $3.3 billion. |
§ | Canadian Natural declared a quarterly cash dividend on common shares of C$0.23 per share payable on October 1, 2015. |
Six Months Ended Jun 30
|
||||||||||||||||
2015
|
2014
|
|||||||||||||||
(number of wells)
|
Gross
|
Net
|
Gross
|
Net
|
||||||||||||
Crude oil
|
54
|
47
|
470
|
425
|
||||||||||||
Natural gas
|
16
|
11
|
48
|
38
|
||||||||||||
Dry
|
2
|
2
|
6
|
5
|
||||||||||||
Subtotal
|
72
|
60
|
524
|
468
|
||||||||||||
Stratigraphic test / service wells
|
128
|
92
|
353
|
352
|
||||||||||||
Total
|
200
|
152
|
877
|
820
|
||||||||||||
Success rate (excluding stratigraphic test / service wells)
|
97%
|
|
99%
|
|
§ | As a direct result of the decrease in crude oil and natural gas pricing and other external events, the Company has proactively reduced its 2015 drilling programs. Drilling activity in Q2/15 consisted of 13 net wells compared to 191 net wells in Q2/14. |
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015
|
Jun 30
2014 |
||||||||||||||||
Crude oil and NGLs production (bbl/d)
|
270,021
|
286,333
|
285,740
|
278,133
|
275,979
|
|||||||||||||||
Net wells targeting crude oil
|
4
|
40
|
151
|
44
|
414
|
|||||||||||||||
Net successful wells drilled
|
4
|
38
|
149
|
42
|
409
|
|||||||||||||||
Success rate
|
100%
|
|
95%
|
|
99%
|
|
95%
|
|
99%
|
|
4
|
Canadian Natural Resources Limited
|
§ | Quarterly production volumes of North America crude oil and NGLs were 270,021 bbl/d in Q2/15, a decrease of 6% from both Q2/14 and Q1/15 levels respectively. |
§ | As expected, North America light crude oil and NGL quarterly production averaged 89,226 bbl/d in Q2/15. Production volumes decreased 4% and 9% from Q2/14 levels and Q1/15 levels respectively, largely as a result of expected production declines offset by the modest light crude oil drilling program in place. North America light crude oil drilling activity consisted of 4 wells in the first half of 2015 compared to 52 net wells in the first half of 2014, a 92% reduction. |
§ | Despite the reduction in production volumes, North America light crude oil and NGL quarterly operating costs decreased to $15.29/bbl in Q2/15, 13% lower than Q2/14 levels of $17.56/bbl and 6% lower than Q1/15 levels of $16.23/bbl. |
§ | Pelican Lake operations achieved record quarterly heavy crude oil production volumes of 52,015 bbl/d, a 5% increase from Q2/14 levels and a 2% increase from Q1/15 levels. Canadian Natural continues to achieve success in developing, implementing and optimizing the leading edge polymer flood technology at Pelican Lake. |
§ | Operational efficiencies continue to be a focus at Pelican Lake. Industry leading quarterly operating costs decreased to $6.98/bbl, 22% lower than Q2/14 and 19% lower than Q1/15. |
§ | In Q2/15, primary heavy crude oil production averaged 128,780 bbl/d, a decrease of 10% and 6% from Q2/14 and Q1/15 levels respectively. The decrease in production volumes reflects a significantly reduced drilling program of 4 net wells in Q2/15 compared to 122 net wells in Q2/14, as well as the Company’s prudent decision to shut-in approximately 4,000 bbl/d of primary heavy crude oil production as a result of unfavorable economic conditions. |
§ | The strength of Canadian Natural’s primary heavy crude oil asset base is its strong operating free cash flow established by achieving low operating costs. As demonstrated, primary heavy crude oil quarterly operating costs decreased in Q2/15 to $14.92/bbl compared to $17.61/bbl in Q2/14 and $17.21/bbl in Q1/15, cost reductions of 15% and 13% respectively. |
Three Months Ended
|
||||||||||||||||||||
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015
|
Jun 30
2014 |
||||||||||||||||
Bitumen production (bbl/d)
|
105,019
|
146,086
|
114,414
|
125,438
|
98,335
|
|||||||||||||||
Net wells targeting bitumen
|
–
|
3
|
3
|
3
|
14
|
|||||||||||||||
Net successful wells drilled
|
–
|
3
|
3
|
3
|
14
|
|||||||||||||||
Success rate
|
–
|
100%
|
|
100%
|
|
100%
|
|
100%
|
|
§ | In Q2/15, thermal in situ production volumes averaged 105,019 bbl/d, a decrease of 8% and 28% from Q2/14 and Q1/15 production volume levels respectively. The decrease in Q2/15 from Q1/15 production volumes primarily reflects reduced production volumes impacted by the cyclic nature of Primrose operations, and the Northeastern Alberta forest fires from late May to early June that caused thermal operations at Primrose to temporarily shut down and as well as production curtailments at Kirby South. |
§ | At Kirby South, Q2/15 production volumes were curtailed as a result of the shut-down of the Cold Lake sales pipeline due to the forest fires. Despite the impact of the forest fires, production volumes increased to 26,193 bbl/d as operations continue to ramp up to the targeted 40,000 bbl/d of design capacity. The reservoir continues to perform as expected with very good thermal efficiencies. For wells on Steam Assisted Gravity Drainage (“SAGD”), the steam to oil ratio (“SOR”) in Q2/15 was 2.6. For July 2015, Kirby South’s production volumes averaged approximately 32,000 bbl/d. |
§ | The Company continues to progress the low pressure steamflood operations at Primrose East Area 1 and the low pressure cyclic steam stimulation (“CSS”) operations at Primrose East Area 2. Operations at Primrose East are exceeding expectations, and due to the cyclic nature of operations at Primrose East Area 2, current production volumes are ranging from 15,000 bbl/d to 20,000 bbl/d. |
Canadian Natural Resources Limited
|
5
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
||||||||||||||||
Natural gas production (MMcf/d)
|
1,716
|
1,713
|
1,606
|
1,715
|
1,378
|
|||||||||||||||
Net wells targeting natural gas
|
2
|
9
|
13
|
11
|
38
|
|||||||||||||||
Net successful wells drilled
|
2
|
9
|
13
|
11
|
38
|
|||||||||||||||
Success rate
|
100%
|
|
100%
|
|
100%
|
|
100%
|
|
100%
|
|
§ | North America natural gas production reached record quarterly levels averaging 1,716 MMcf/d for Q2/15, an increase of 7% from Q2/14 levels and comparable to Q1/15 levels. The increase from Q2/14 levels resulted from additional production volumes acquired in 2014, complemented by a focused liquids-rich natural gas drilling program. |
§ | Operations at Septimus, Canadian Natural’s liquids-rich Montney natural gas play in British Columbia, continue to perform above expectations, with industry leading quarterly operating costs of approximately $0.18/Mcfe in Q2/15. |
§ | North America natural gas production volumes during Q2/15 were impacted by 46 MMcf/d as a result of transportation restrictions on the NOVA pipeline system. Restricted pipeline take away capacity anticipated in Northwest Alberta during Q3/15 is currently expected to lower the Company’s North America natural gas production volumes by approximately 80 MMcf/d. Canadian Natural’s Q3/15 total natural gas production guidance reflects these impacts and is targeted to range from 1,670 MMcf/d to 1,690 MMcf/d. |
§ | North America natural gas quarterly operating costs were $1.28/Mcf in Q2/15, a 14% decrease from Q2/14 levels of $1.48/Mcf, and a 7% decrease from Q1/15 levels of $1.38/Mcf, reflecting a continued focus on cost optimization. |
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015
|
Jun 30
2014 |
||||||||||||||||
Crude oil production (bbl/d)
|
||||||||||||||||||||
North Sea
|
20,330
|
23,036
|
12,615
|
21,676
|
14,654
|
|||||||||||||||
Offshore Africa
|
17,070
|
13,188
|
13,164
|
15,139
|
11,984
|
|||||||||||||||
Natural gas production (MMcf/d)
|
||||||||||||||||||||
North Sea
|
38
|
34
|
5
|
36
|
6
|
|||||||||||||||
Offshore Africa
|
25
|
24
|
23
|
24
|
22
|
|||||||||||||||
Net wells targeting crude oil
|
1.4
|
0.6
|
1.7
|
2.0
|
1.7
|
|||||||||||||||
Net successful wells drilled
|
1.4
|
0.6
|
1.7
|
2.0
|
1.7
|
|||||||||||||||
Success rate
|
100%
|
|
100%
|
|
100%
|
|
100%
|
|
100%
|
|
§ | International crude oil production averaged 37,400 bbl/d during Q2/15, an increase of 45% from Q2/14 levels and a 3% increase from Q1/15 levels. The increase in production over Q2/14 levels primarily reflected the reinstatement of production from both the Banff FPSO and the Tiffany platform during 2014. The increase in production from Q1/15 was primarily due to bringing new wells onstream at the Baobab and Espoir fields during Q2/15, offset by a planned turnaround performed at Ninian that commenced in late June 2015 and was completed in July 2015. |
§ | The infill drilling programs at the Espoir and Baobab fields in Côte d’Ivoire continue to be successfully executed with results exceeding expectations. |
— | To date, 3 gross wells have been drilled at Espoir, adding net production of approximately 4,500 bbl/d. Espoir is targeted to add overall net production volumes of 5,900 bbl/d through a 10 gross well program which includes 4 water injection wells (5.9 net well program) and is currently tracking below sanctioned costs. |
6
|
Canadian Natural Resources Limited
|
— | To date, Canadian Natural drilled 1 gross well at Baobab, adding net production volumes of approximately 2,000 bbl/d. Production from the second gross well is targeted to come on stream in the third quarter of 2015. Baobab is targeted to add overall net production volumes of 11,000 bbl/d through a 6 gross well program (3.4 net well program), which is currently tracking below sanctioned costs. |
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
||||||||||||||||
Synthetic crude oil production (bbl/d) (1)
|
96,607
|
134,166
|
119,236
|
115,283
|
116,182
|
(1) | The Company has commenced production of diesel for internal use at Horizon. Second quarter 2015 SCO production before royalties excludes 2,410 bbl/d of SCO consumed internally as diesel (first quarter 2015 – 1,676 bbl/d; second quarter 2014 – nil; six months ended June 30, 2015 – 2,045 bbl/d; six months ended June 30, 2014 – nil). |
§ | Horizon quarterly production averaged 96,607 bbl/d of SCO, a decrease of 19% and 28% from Q2/14 and Q1/15 levels respectively. Q2/15 production volumes were lower than targeted volumes primarily as a result of an extension of the 2015 planned maintenance turnaround from 10 days to 15 days in June, to address necessary found work, and a slightly slower than expected start-up of operations post-turnaround. July production volumes averaged approximately 124,200 bbl/d, near the low end of the targeted utilization rate range of 92% to 96%. Q3/15 production guidance is targeted to range from 124,000 bbl/d to 131,000 bbl/d, with a targeted utilization rate of 93% at the midpoint. 2015 annual production guidance remains unchanged at 121,000 bbl/d to 131,000 bbl/d. |
§ | Canadian Natural continues to execute on its strategy to transition to a longer life, low decline asset base while delivering significant and sustainable production. Canadian Natural’s staged expansion of Horizon to 250,000 bbl/d of SCO production capacity continues to progress ahead of schedule. Canadian Natural has committed to approximately 82% of the Engineering, Procurement and Construction contracts with over 78% of the construction contracts awarded to date, 85% being lump sum, ensuring greater cost certainty and efficiency. |
§ | Overall Horizon Phase 2/3 expansion is 67% physically complete as at Q2/15: |
— | Reliability – Tranche 2 is 100% physically complete. Completion occurred in 2014 resulting in increased performance and overall production reliability. This contributed approximately 5% increase in production levels from Phase 1 production levels. |
— | Directive 74 includes technological investment and research into tailings management. This project remains on track and is 55% physically complete. |
— | Phase 2A is a coker expansion that was originally scheduled to be completed in mid-2015; however, due to strong construction performance and the early completion of the coker installation, the Company accelerated the tie-in to August 2014. The expanded Coker Unit is now fully operational and the project was completed on time and below budget. Horizon SCO production levels increased by approximately 12,000 bbl/d with the completion of the coker tie-in. Through the completion of Phase 2A, additional coker capacity and equipment were added, increasing the plant nameplate capacity to 133,000 bbl/d. New equipment performance combined with an optimized mining strategy have increased the stability of the extraction and upgrading processes, resulting in a further increase to plant nameplate capacity to 137,000 bbl/d. |
— | Phase 2B is 62% physically complete. This Phase expands the capacity of major components such as gas/oil hydrotreatment, froth treatment and the hydrogen plant. Due to continued strong construction performance on the Horizon expansion, certain components of this project will be tied-in during the Q2/16 turnaround. Production volumes after the turnaround are targeted to increase by 4,000 bbl/d in Q3/16 and 10,000 bbl/d in Q4/16, above the original planned production ramp up. Full commissioning of the Phase 2B equipment will be completed as planned in late 2016, adding 45,000 bbl/d of production capacity. |
— | Phase 3 is currently on budget and on schedule. This Phase is 59% physically complete, and includes the addition of extraction trains. This phase is targeted to increase production capacity by 80,000 bbl/d in late 2017 and will result in additional reliability, redundancy and significant operating cost savings for the Horizon project. |
Canadian Natural Resources Limited
|
7
|
§ | The development of leased acreage is ongoing and lease requests on undeveloped acreage continue to be evaluated. Total drilling activity for the first half of 2015 consisted of 151 wells with 146 drilled by third parties and 5 drilled by Canadian Natural. Compared to Q4/14, total Q1/15 production volumes on the royalty lands decreased by 195 BOE/d, however, crude oil and NGL production increased by 60 bbl/d. |
§ | The Company continues to focus on lease compliance, well commitments, offset drilling obligations and compensatory royalties payable. |
§ | Royalty production volumes highlighted below are not reported in Canadian Natural’s quarterly production volumes. Third party royalty revenues are included in reported Product Sales in the Company’s consolidated statement of earnings. |
Q1/15
|
Q4/14
|
|||||||
Natural gas (MMcf/d)
|
22.4
|
24.0
|
||||||
Crude oil (bbl/d)
|
4,263
|
4,203
|
||||||
NGLs (bbl/d)
|
538
|
534
|
||||||
Total (BOE/d)
|
8,537
|
8,732
|
Royalty volumes for Q1/15 attributable to
|
||||||||||||
Third
Party
|
Canadian
Natural (2)
|
Total
|
||||||||||
Natural gas (MMcf/d)
|
19.2
|
3.2
|
22.4
|
|||||||||
Crude oil (bbl/d)
|
3,618
|
645
|
4,263
|
|||||||||
NGLs (bbl/d)
|
490
|
48
|
538
|
|||||||||
Total (BOE/d)
|
7,305
|
1,232
|
8,537
|
Royalty revenue for Q1/15 attributable to
|
||||||||||||
($ millions)
|
Third
Party
|
Canadian
Natural (2)
|
Total
|
|||||||||
Natural gas
|
$
|
4
|
1
|
5
|
||||||||
Crude oil
|
$
|
15
|
2
|
17
|
||||||||
NGLs
|
$
|
1
|
–
|
1
|
||||||||
Other revenue (3)
|
$
|
1
|
–
|
1
|
||||||||
Total
|
$
|
21
|
3
|
24
|
8
|
Canadian Natural Resources Limited
|
Royalty revenue for Q1/15 attributable to
|
||||||||||||
($ millions)
|
Third
Party
|
Canadian
Natural (2)
|
Total
|
|||||||||
Fee title
|
$
|
13
|
2
|
15
|
||||||||
Gross overriding royalty (4)
|
$
|
7
|
1
|
8
|
||||||||
Other revenue (3)
|
$
|
1
|
–
|
1
|
||||||||
Total
|
$
|
21
|
3
|
24
|
Q1/15
|
||||
Natural gas ($/Mcf)
|
$
|
2.59
|
||
Crude oil ($/bbl)
|
$
|
42.89
|
||
NGLs ($/bbl)
|
$
|
27.83
|
||
Total ($/BOE)
|
$
|
31.35
|
Leased to
|
||||||||||||
(gross acres, millions)
|
Third Party
and Unleased
|
Canadian
Natural (2)
|
Total
|
|||||||||
Fee title (5)
|
3.08
|
0.26
|
3.34
|
|||||||||
Gross overriding royalty (4)
|
1.83
|
1.68
|
3.51
|
|||||||||
Total
|
4.91
|
1.94
|
6.85
|
(1) | Based on the Company’s current estimate of revenue and volumes attributable to the noted period. |
(2) | Indicates Canadian Natural is both the Lessor and Lessee, thereby incurring intercompany royalties; in addition there are certain Canadian Natural fee title lands where the Company has production where no royalty burden has been recognized in this table. |
(3) | Includes sulphur revenue, bonus payments, lease rentals and compliance revenue. |
(4) | Includes Net Profit Interests and other royalties. |
(5) | Includes fee title and freehold lands. |
Canadian Natural Resources Limited
|
9
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
||||||||||||||||
Crude oil and NGLs pricing
|
||||||||||||||||||||
WTI benchmark price (US$/bbl) (1)
|
$
|
57.96
|
$
|
48.57
|
$
|
102.98
|
$
|
53.29
|
$
|
100.81
|
||||||||||
WCS blend differential from WTI (%) (2)
|
20%
|
|
30%
|
|
19%
|
|
25%
|
|
21%
|
|
||||||||||
SCO price (US$/bbl)
|
$
|
60.61
|
$
|
45.26
|
$
|
103.87
|
$
|
52.98
|
$
|
100.18
|
||||||||||
Condensate benchmark pricing (US$/bbl)
|
$
|
57.98
|
$
|
45.59
|
$
|
105.15
|
$
|
51.82
|
$
|
103.85
|
||||||||||
Average realized pricing before risk management (C$/bbl) (3)
|
$
|
53.09
|
$
|
37.03
|
$
|
87.03
|
$
|
44.62
|
$
|
83.68
|
||||||||||
Natural gas pricing
|
||||||||||||||||||||
AECO benchmark price (C$/GJ)
|
$
|
2.53
|
$
|
2.80
|
$
|
4.44
|
$
|
2.67
|
$
|
4.48
|
||||||||||
Average realized pricing before risk
management (C$/Mcf) |
$
|
3.06
|
$
|
3.38
|
$
|
5.06
|
$
|
3.22
|
$
|
5.32
|
(1) | West Texas Intermediate (“WTI”). |
(2) | Western Canadian Select (“WCS”). |
(3) | Average crude oil and NGL pricing excludes SCO. Pricing is net of blending costs and excluding risk management activities. |
Benchmark Pricing
|
WTI Pricing (US$/bbl) |
WCS Blend Differential
from WTI
(%)
|
WCS Blend Differential
from WTI
(US$/bbl) |
SCO
Differential
from WTI
(US$/bbl)
|
Dated Brent Differential
from WTI
(US$/bbl)
|
Condensate Differential
from WTI
(US$/bbl) |
||||||||||||||||||
2015
|
||||||||||||||||||||||||
April
|
$
|
54.63
|
26%
|
|
$
|
14.37
|
$
|
0.86
|
$
|
5.13
|
$
|
0.68
|
||||||||||||
May
|
$
|
59.37
|
20%
|
|
$
|
11.87
|
$
|
3.43
|
$
|
4.95
|
$
|
1.54
|
||||||||||||
June
|
$
|
59.83
|
14%
|
|
$
|
8.54
|
$
|
3.63
|
$
|
1.87
|
$
|
(2.22
|
)
|
|||||||||||
July
|
$
|
50.93
|
15%
|
|
$
|
7.44
|
$
|
2.62
|
$
|
5.61
|
$
|
(4.35
|
)
|
|||||||||||
August*
|
$
|
47.26
|
28%
|
|
$
|
13.41
|
$
|
(0.64
|
)
|
$
|
4.33
|
$
|
(1.36
|
)
|
||||||||||
September*
|
$
|
47.72
|
33%
|
|
$
|
15.95
|
$
|
(2.75
|
)
|
$
|
4.33
|
$
|
1.25
|
§ | Volatility in supply and demand factors and geopolitical events continued to affect WTI and Brent pricing. The Organization of the Petroleum Exporting Countries’ (“OPEC”) decision to maintain crude oil production quotas resulted in a year over year decline in benchmark pricing. Crude oil pricing increased in Q2/15 from Q1/15 as a result of slower US shale oil production growth, market response to reduced rig counts and lower crude oil inventories at Cushing as a result of higher refinery utilizations. |
§ | The WCS differential to WTI averaged US$11.60/bbl or 20% in Q2/15 compared to US$20.03/bbl or 19% in Q2/14. The WCS heavy differential narrowed during Q2/15 compared to Q1/15 due to increased refinery utilization and seasonal demand. August 2015 and September 2015 indications of the WCS heavy differential are trending higher to US$13.41/bbl or 28% and US$15.95/bbl or 33%, respectively. This widening is mainly due to planned refinery turnarounds, which are typical during this time of year. Seasonal demand fluctuations, changes in transportation logistics and refinery utilization and shutdowns will continue to be reflected in WCS pricing. |
§ | Canadian Natural contributed approximately 162,000 bbl/d of its heavy crude oil stream to the WCS blend in Q2/15. The Company remains the largest contributor to the WCS blend, accounting for 47% of the total blend. |
§ |
SCO pricing averaged US$60.61/bbl during Q2/15 compared to US$45.26/bbl in Q1/15, as a result of an increase in WTI benchmark pricing and industry-wide oil sands production interruptions caused by planned and unplanned production outages. Year over year SCO pricing has decreased resulting from an overall decline in WTI benchmark pricing.
|
10
|
Canadian Natural Resources Limited
|
§ | AECO natural gas pricing in Q2/15 averaged $2.53/GJ, a decrease of 43% and 10% from Q2/14 and Q1/15 pricing respectively. In Q2/15, US natural gas production continued to grow while natural gas inventories remained at normal industry levels, leading to downward pressure on natural gas prices. Natural gas prices were lower in Q2/15 compared to Q1/15 primarily due to seasonal demand. Warmer weather and adequate storage levels primarily resulted in lower natural gas pricing in Q2/15 compared to Q2/14, which had lower than average storage levels due to the cold winter temperatures in 2014. |
§ | The Company’s strategy is to maintain a diverse portfolio balanced across various commodity types. The Company achieved production of approximately 805,500 BOE/d for Q2/15 with approximately 97% of production located in G8 countries. |
§ | During the second quarter, the Company priced C$500 million principal amount of notes through the reopening of its 2.89% medium-term notes, series 2, due August 14, 2020. |
§ | In Q2/15, the Company increased its $1,500 million revolving syndicated credit facility to $2,425 million and the maturity date was extended to June 2019. The $3,000 million revolving syndicated credit facility was reduced to $2,425 million and the maturity date was extended to June 2020. As a result, the Company’s available liquidity increased by $350 million. |
§ | Canadian Natural has a strong balance sheet with debt to book capitalization of 37% and debt to EBITDA of 2.0x at June 30, 2015. All of the Company’s credit facilities are now subject to a revised financial covenant that the Consolidated Debt to Capitalization Ratio, as defined in the credit agreements, shall not be more than 0.65 to 1.0. |
§ | Canadian Natural maintains significant financial stability and liquidity represented in part by bank credit facilities. As at June 30, 2015, the Company had in place bank credit facilities of $7,479 million, of which $3,272 million was available. |
§ | The Company’s commodity hedging program is utilized to protect investment returns, support ongoing balance sheet strength and the cash flow for its capital expenditure programs. Details of the Company’s commodity hedging program can be found on the Company’s website at www.cnrl.com. |
§ | Canadian Natural declared a quarterly cash dividend on common shares of C$0.23 per share payable on October 1, 2015. |
§ | The Company has a strong balance sheet and cash flow generation which enables it to weather volatility in commodity prices. Canadian Natural retains additional capital expenditure program flexibility to proactively adapt to changing market conditions. |
Canadian Natural Resources Limited
|
11
|
12
|
Canadian Natural Resources Limited
|
Canadian Natural Resources Limited
|
13
|
($ millions, except per common share amounts) | Three Months Ended | Six Months Ended | |||||||||||||||||||
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
|||||||||||||||||
Product sales
|
$
|
3,662
|
$
|
3,226
|
$
|
6,113
|
$
|
6,888
|
$
|
11,081
|
|||||||||||
Net earnings (loss)
|
$
|
(405
|
)
|
$
|
(252
|
)
|
$
|
1,070
|
$
|
(657
|
)
|
$
|
1,692
|
||||||||
Per common share |
– basic
|
$
|
(0.37
|
)
|
$
|
(0.23
|
)
|
$
|
0.98
|
$
|
(0.60
|
)
|
$
|
1.55
|
|||||||
– diluted
|
$
|
(0.37
|
)
|
$
|
(0.23
|
)
|
$
|
0.97
|
$
|
(0.60
|
)
|
$
|
1.54
|
||||||||
Adjusted net earnings from operations (1)
|
$
|
178
|
$
|
21
|
$
|
1,150
|
$
|
199
|
$
|
2,071
|
|||||||||||
Per common share |
– basic
|
$
|
0.16
|
$
|
0.02
|
$
|
1.05
|
$
|
0.18
|
$
|
1.90
|
||||||||||
– diluted
|
$
|
0.16
|
$
|
0.02
|
$
|
1.04
|
$
|
0.18
|
$
|
1.89
|
|||||||||||
Cash flow from operations (2)
|
$
|
1,503
|
$
|
1,370
|
$
|
2,633
|
$
|
2,873
|
$
|
4,779
|
|||||||||||
Per common share |
– basic
|
$
|
1.38
|
$
|
1.25
|
$
|
2.41
|
$
|
2.63
|
$
|
4.38
|
||||||||||
– diluted
|
$
|
1.37
|
$
|
1.25
|
$
|
2.39
|
$
|
2.62
|
$
|
4.36
|
|||||||||||
Capital expenditures, net of dispositions
|
$
|
1,297
|
$
|
1,412
|
$
|
5,456
|
$
|
2,709
|
$
|
7,349
|
(1) | Adjusted net earnings from operations is a non-GAAP measure that represents net earnings adjusted for certain items of a non-operational nature. The Company evaluates its performance based on adjusted net earnings from operations. The reconciliation “Adjusted Net Earnings from Operations” presents the after-tax effects of certain items of a non-operational nature that are included in the Company’s financial results. Adjusted net earnings from operations may not be comparable to similar measures presented by other companies. |
(2) | Cash flow from operations is a non-GAAP measure that represents net earnings adjusted for non-cash items before working capital adjustments. The Company evaluates its performance based on cash flow from operations. The Company considers cash flow from operations a key measure as it demonstrates the Company’s ability to generate the cash flow necessary to fund future growth through capital investment and to repay debt. The reconciliation “Cash Flow from Operations” presents certain non-cash items that are included in the Company’s financial results. Cash flow from operations may not be comparable to similar measures presented by other companies. |
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
($ millions)
|
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
|||||||||||||||
Net earnings (loss) as reported
|
$
|
(405
|
)
|
$
|
(252
|
)
|
$
|
1,070
|
$
|
(657
|
)
|
$
|
1,692
|
|||||||
Share-based compensation, net of tax (1)
|
(79
|
)
|
64
|
189
|
(15
|
)
|
332
|
|||||||||||||
Unrealized risk management loss, net of tax (2)
|
162
|
9
|
44
|
171
|
82
|
|||||||||||||||
Unrealized foreign exchange (gain) loss, net of tax (3)
|
(76
|
)
|
413
|
(153
|
)
|
337
|
(35
|
)
|
||||||||||||
Equity (gain) loss from investment, net of tax (4)
|
(3
|
)
|
15
|
–
|
12
|
–
|
||||||||||||||
Effect of statutory tax rate and other legislative changes on deferred income
tax liabilities (5)
|
579
|
(228
|
)
|
–
|
351
|
–
|
||||||||||||||
Adjusted net earnings from operations
|
$
|
178
|
$
|
21
|
$
|
1,150
|
$
|
199
|
$
|
2,071
|
(1) | The Company’s employee stock option plan provides for a cash payment option. Accordingly, the fair value of the outstanding vested options is recorded as a liability on the Company’s balance sheets and periodic changes in the fair value are recognized in net earnings or are capitalized to Oil Sands Mining and Upgrading construction costs. |
(2) | Derivative financial instruments are recorded at fair value on the Company’s balance sheets, with changes in the fair value of non-designated hedges recognized in net earnings. The amounts ultimately realized may be materially different than reflected in the financial statements due to changes in prices of the underlying items hedged, primarily crude oil, natural gas and foreign exchange. |
(3) | Unrealized foreign exchange gains and losses result primarily from the translation of US dollar denominated long-term debt to period-end exchange rates, partially offset by the impact of cross currency swaps, and are recognized in net earnings. |
(4) | The Company's investment in the 50% owned North West Redwater Partnership is accounted for using the equity method of accounting. The non-cash equity (gain) loss from investment represents the Company's pro rata share of the North West Redwater Partnership's accounting (gain) loss. |
(5) | During the second quarter of 2015, the Alberta government enacted legislation that increased the provincial corporate income tax rate from 10% to 12% effective July 1, 2015. As a result of this income tax rate increase, the Company’s deferred income tax liability was increased by $579 million. During the first quarter of 2015, the UK government enacted tax rate reductions to the supplementary charge on oil and gas profits and the Petroleum Revenue Tax (“PRT”), and replaced the Brownfield Allowance with a new Investment Allowance, resulting in a decrease in the Company’s deferred income tax liability of $228 million. |
14
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
($ millions)
|
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
|||||||||||||||
Net earnings (loss)
|
$
|
(405
|
)
|
$
|
(252
|
)
|
$
|
1,070
|
$
|
(657
|
)
|
$
|
1,692
|
|||||||
Non-cash items:
|
||||||||||||||||||||
Depletion, depreciation and amortization
|
1,280
|
1,355
|
1,237
|
2,635
|
2,248
|
|||||||||||||||
Share-based compensation
|
(79
|
)
|
64
|
189
|
(15
|
)
|
332
|
|||||||||||||
Asset retirement obligation accretion
|
43
|
43
|
50
|
86
|
95
|
|||||||||||||||
Unrealized risk management loss
|
215
|
14
|
54
|
229
|
103
|
|||||||||||||||
Unrealized foreign exchange (gain) loss
|
(76
|
)
|
413
|
(153
|
)
|
337
|
(35
|
)
|
||||||||||||
Equity (gain) loss from investment
|
(3
|
)
|
15
|
(3
|
)
|
12
|
(2
|
)
|
||||||||||||
Deferred income tax expense (recovery)
|
528
|
(282
|
)
|
189
|
246
|
346
|
||||||||||||||
Cash flow from operations
|
$
|
1,503
|
$
|
1,370
|
$
|
2,633
|
$
|
2,873
|
$
|
4,779
|
§ | lower crude oil and NGLs netbacks in the North America and North Sea segments; |
§ | lower realized SCO prices; |
§ | lower natural gas netbacks in the North America segment; and |
§ | higher depletion, depreciation and amortization expense; |
§ | higher crude oil and NGLs and natural gas sales volumes in the North America and North Sea segments; |
§ | higher realized risk management gains; and |
§ | the impact of a weaker Canadian dollar relative to the US dollar. |
§ | lower crude oil and NGLs netbacks across all Exploration and Production segments; |
§ | lower SCO sales volumes and realized SCO prices; |
§ | lower crude oil and NGLs sales volumes in the North America segment; and |
§ | lower natural gas netbacks in the North America segment; |
Canadian Natural Resources Limited
|
15
|
§ | higher natural gas sales volumes in the North America and North Sea segments; |
§ | higher realized risk management gains; and |
§ | the impact of a weaker Canadian dollar relative to the US dollar. |
§ | higher crude oil and NGLs netbacks in the North America segment; |
§ | higher realized SCO prices; and |
§ | higher crude oil and NGLs sales volumes in the North Sea and Offshore Africa segments; |
§ | lower crude oil and NGLs and SCO sales volumes in the North America and Oil Sands Mining and Upgrading segments; |
§ | lower natural gas netbacks in the North America segment; |
§ | lower crude oil netbacks in the Offshore Africa segment; and |
§ | lower realized risk management gains. |
($ millions, except per common share
amounts)
|
Jun 30
2015 |
Mar 31
2015 |
Dec 31
2014 |
Sep 30
2014 |
||||||||||||
Product sales
|
$
|
3,662
|
$
|
3,226
|
$
|
4,850
|
$
|
5,370
|
||||||||
Net earnings (loss)
|
$
|
(405
|
)
|
$
|
(252
|
)
|
$
|
1,198
|
$
|
1,039
|
||||||
Net earnings (loss) per common share
|
||||||||||||||||
– basic
|
$
|
(0.37
|
)
|
$
|
(0.23
|
)
|
$
|
1.10
|
$
|
0.95
|
||||||
– diluted
|
$
|
(0.37
|
)
|
$
|
(0.23
|
)
|
$
|
1.09
|
$
|
0.94
|
||||||
($ millions, except per common share
amounts)
|
Jun 30
2014 |
Mar 31
2014 |
Dec 31
2013 |
Sep 30
2013 |
||||||||||||
Product sales
|
$
|
6,113
|
$
|
4,968
|
$
|
4,330
|
$
|
5,284
|
||||||||
Net earnings (loss)
|
$
|
1,070
|
$
|
622
|
$
|
413
|
$
|
1,168
|
||||||||
Net earnings (loss) per common share
|
||||||||||||||||
– basic
|
$
|
0.98
|
$
|
0.57
|
$
|
0.38
|
$
|
1.07
|
||||||||
– diluted
|
$
|
0.97
|
$
|
0.57
|
$
|
0.38
|
$
|
1.07
|
16
|
Canadian Natural Resources Limited
|
§ | Crude oil pricing – The impact of increased shale oil production in North America, fluctuating global supply/demand, the impact of geopolitical uncertainties on worldwide benchmark pricing, the impact of the WCS Heavy Differential from the West Texas Intermediate reference location at Cushing, Oklahoma (“WTI”) in North America and the impact of the differential between WTI and Dated Brent benchmark pricing in the North Sea and Offshore Africa. |
§ | Natural gas pricing – The impact of fluctuations in both the demand for natural gas and inventory storage levels, and the impact of increased shale gas production in the US. |
§ | Crude oil and NGLs sales volumes – Fluctuations in production due to the cyclic nature of the Company’s Primrose thermal projects, production from Kirby South, the results from the Pelican Lake water and polymer flood projects, the strong heavy crude oil drilling program throughout 2013 and 2014, the impact and timing of acquisitions, and the impact of turnarounds at Horizon. Sales volumes also reflected fluctuations due to timing of liftings and maintenance activities in the North Sea and Offshore Africa. |
§ | Natural gas sales volumes – Fluctuations in production due to the Company’s allocation of capital to higher return crude oil projects, as well as natural decline rates, shut-in natural gas production due to pricing and the impact and timing of acquisitions. |
§ | Production expense – Fluctuations primarily due to the impact of the demand for services, fluctuations in product mix and production, the impact of seasonal costs that are dependent on weather, cost optimizations across all segments, the impact and timing of acquisitions, and turnarounds at Horizon. |
§ | Depletion, depreciation and amortization – Fluctuations due to changes in sales volumes including the impact and timing of acquisitions, proved reserves, asset retirement obligations, finding and development costs associated with crude oil and natural gas exploration, estimated future costs to develop the Company’s proved undeveloped reserves, fluctuations in depletion, depreciation and amortization expense in the North Sea resulting from the planned early cessation of production at the Murchison platform, and the impact of turnarounds at Horizon. |
§ | Share-based compensation – Fluctuations due to the determination of fair market value based on the Black-Scholes valuation model of the Company’s share-based compensation liability. |
§ | Risk management – Fluctuations due to the recognition of gains and losses from the mark-to-market and subsequent settlement of the Company’s risk management activities. |
§ | Foreign exchange rates – Fluctuations in the Canadian dollar relative to the US dollar, which impacted the realized price the Company received for its crude oil and natural gas sales, as sales prices are based predominately on US dollar denominated benchmarks. Fluctuations in realized and unrealized foreign exchange gains and losses are also recorded with respect to US dollar denominated debt, partially offset by the impact of cross currency swap hedges. |
§ | Income tax expense – Fluctuations in income tax expense include statutory tax rate and other legislative changes substantively enacted in the various periods. |
§ | Gains on corporate acquisitions/disposition of properties – Fluctuations due to the recognition of gains on corporate acquisitions/dispositions in the fourth quarter of 2014 and the third quarter of 2013. |
Canadian Natural Resources Limited
|
17
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
||||||||||||||||
WTI benchmark price (US$/bbl)
|
$
|
57.96
|
$
|
48.57
|
$
|
102.98
|
$
|
53.29
|
$
|
100.81
|
||||||||||
Dated Brent benchmark price (US$/bbl)
|
$
|
61.95
|
$
|
53.80
|
$
|
109.63
|
$
|
57.90
|
$
|
108.92
|
||||||||||
WCS blend differential from WTI (US$/bbl)
|
$
|
11.60
|
$
|
14.75
|
$
|
20.03
|
$
|
13.16
|
$
|
21.64
|
||||||||||
WCS blend differential from WTI (%)
|
20%
|
|
30%
|
|
19%
|
|
25%
|
|
21%
|
|
||||||||||
SCO price (US$/bbl)
|
$
|
60.61
|
$
|
45.26
|
$
|
103.87
|
$
|
52.98
|
$
|
100.18
|
||||||||||
Condensate benchmark price (US$/bbl)
|
$
|
57.98
|
$
|
45.59
|
$
|
105.15
|
$
|
51.82
|
$
|
103.85
|
||||||||||
NYMEX benchmark price (US$/MMBtu)
|
$
|
2.67
|
$
|
2.96
|
$
|
4.57
|
$
|
2.81
|
$
|
4.73
|
||||||||||
AECO benchmark price (C$/GJ)
|
$
|
2.53
|
$
|
2.80
|
$
|
4.44
|
$
|
2.67
|
$
|
4.48
|
||||||||||
US/Canadian dollar average exchange rate
(US$)
|
$
|
0.8132
|
$
|
0.8057
|
$
|
0.9171
|
$
|
0.8095
|
$
|
0.9118
|
18
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
||||||||||||||||
Crude oil and NGLs (bbl/d)
|
||||||||||||||||||||
North America – Exploration and Production
|
375,040
|
432,419
|
400,154
|
403,571
|
374,314
|
|||||||||||||||
North America – Oil Sands Mining and Upgrading (1)
|
96,607
|
134,166
|
119,236
|
115,283
|
116,182
|
|||||||||||||||
North Sea
|
20,330
|
23,036
|
12,615
|
21,676
|
14,654
|
|||||||||||||||
Offshore Africa
|
17,070
|
13,188
|
13,164
|
15,139
|
11,984
|
|||||||||||||||
509,047
|
602,809
|
545,169
|
555,669
|
517,134
|
||||||||||||||||
Natural gas (MMcf/d)
|
||||||||||||||||||||
North America
|
1,716
|
1,713
|
1,606
|
1,715
|
1,378
|
|||||||||||||||
North Sea
|
38
|
34
|
5
|
36
|
6
|
|||||||||||||||
Offshore Africa
|
25
|
24
|
23
|
24
|
22
|
|||||||||||||||
1,779
|
1,771
|
1,634
|
1,775
|
1,406
|
||||||||||||||||
Total barrels of oil equivalent (BOE/d)
|
805,547
|
898,053
|
817,471
|
851,545
|
751,426
|
|||||||||||||||
Product mix
|
||||||||||||||||||||
Light and medium crude oil and NGLs
|
16%
|
|
15%
|
|
15%
|
|
15%
|
|
15%
|
|
||||||||||
Pelican Lake heavy crude oil
|
6%
|
|
6%
|
|
6%
|
|
6%
|
|
7%
|
|
||||||||||
Primary heavy crude oil
|
16%
|
|
15%
|
|
17%
|
|
15%
|
|
19%
|
|
||||||||||
Bitumen (thermal oil)
|
13%
|
|
16%
|
|
14%
|
|
15%
|
|
13%
|
|
||||||||||
Synthetic crude oil (1)
|
12%
|
|
15%
|
|
15%
|
|
14%
|
|
15%
|
|
||||||||||
Natural gas
|
37%
|
|
33%
|
|
33%
|
|
35%
|
|
31%
|
|
||||||||||
Percentage of product sales (1) (2)
(excluding Midstream revenue) |
||||||||||||||||||||
Crude oil and NGLs
|
84%
|
|
80%
|
|
86%
|
|
82%
|
|
86%
|
|
||||||||||
Natural gas
|
16%
|
|
20%
|
|
14%
|
|
18%
|
|
14%
|
|
(1) | Second quarter 2015 SCO production before royalties excludes 2,410 bbl/d of SCO consumed internally as diesel (first quarter 2015 – 1,676 bbl/d; second quarter 2014 – nil; six months ended June 30, 2015 – 2,045 bbl/d; six months ended June 30, 2014 – nil). |
(2) | Net of blending costs and excluding risk management activities. |
Canadian Natural Resources Limited
|
19
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
||||||||||||||||
Crude oil and NGLs (bbl/d)
|
||||||||||||||||||||
North America – Exploration and Production
|
326,445
|
380,273
|
318,672
|
353,209
|
299,854
|
|||||||||||||||
North America – Oil Sands Mining and Upgrading
|
95,057
|
132,413
|
111,825
|
113,632
|
109,372
|
|||||||||||||||
North Sea
|
20,300
|
22,976
|
12,581
|
21,631
|
14,610
|
|||||||||||||||
Offshore Africa
|
16,342
|
12,586
|
12,733
|
14,475
|
11,256
|
|||||||||||||||
458,144
|
548,248
|
455,811
|
502,947
|
435,092
|
||||||||||||||||
Natural gas (MMcf/d)
|
||||||||||||||||||||
North America
|
1,684
|
1,643
|
1,474
|
1,664
|
1,247
|
|||||||||||||||
North Sea
|
38
|
34
|
5
|
36
|
6
|
|||||||||||||||
Offshore Africa
|
24
|
23
|
19
|
23
|
19
|
|||||||||||||||
1,746
|
1,700
|
1,498
|
1,723
|
1,272
|
||||||||||||||||
Total barrels of oil equivalent (BOE/d)
|
749,210
|
831,637
|
705,480
|
790,196
|
647,101
|
20
|
Canadian Natural Resources Limited
|
Canadian Natural Resources Limited
|
21
|
(bbl)
|
Jun 30
2015 |
Mar 31
2015 |
Dec 31
2014 |
|||||||||
North America – Exploration and Production
|
839,720
|
598,825
|
930,116
|
|||||||||
North America – Oil Sands Mining and Upgrading (SCO)
|
1,074,964
|
1,692,043
|
1,266,063
|
|||||||||
North Sea
|
131,959
|
562,540
|
368,808
|
|||||||||
Offshore Africa
|
1,459,094
|
1,086,222
|
461,997
|
|||||||||
3,505,737
|
3,939,630
|
3,026,984
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
||||||||||||||||
Crude oil and NGLs ($/bbl) (1)
|
||||||||||||||||||||
Sales price (2)
|
$
|
53.09
|
$
|
37.03
|
$
|
87.03
|
$
|
44.62
|
$
|
83.68
|
||||||||||
Transportation
|
2.80
|
2.46
|
2.74
|
2.62
|
2.62
|
|||||||||||||||
Realized sales price, net of transportation
|
50.29
|
34.57
|
84.29
|
42.00
|
81.06
|
|||||||||||||||
Royalties
|
5.91
|
3.83
|
15.62
|
4.82
|
14.90
|
|||||||||||||||
Production expense
|
17.01
|
16.10
|
19.33
|
16.53
|
19.26
|
|||||||||||||||
Netback
|
$
|
27.37
|
$
|
14.64
|
$
|
49.34
|
$
|
20.65
|
$
|
46.90
|
||||||||||
Natural gas ($/Mcf) (1)
|
||||||||||||||||||||
Sales price (2)
|
$
|
3.06
|
$
|
3.38
|
$
|
5.06
|
$
|
3.22
|
$
|
5.32
|
||||||||||
Transportation
|
0.38
|
0.36
|
0.26
|
0.37
|
0.28
|
|||||||||||||||
Realized sales price, net of transportation
|
2.68
|
3.02
|
4.80
|
2.85
|
5.04
|
|||||||||||||||
Royalties
|
0.05
|
0.12
|
0.41
|
0.08
|
0.49
|
|||||||||||||||
Production expense
|
1.39
|
1.44
|
1.52
|
1.42
|
1.56
|
|||||||||||||||
Netback
|
$
|
1.24
|
$
|
1.46
|
$
|
2.87
|
$
|
1.35
|
$
|
2.99
|
||||||||||
Barrels of oil equivalent ($/BOE) (1)
|
||||||||||||||||||||
Sales price (2)
|
$
|
38.85
|
$
|
30.57
|
$
|
64.69
|
$
|
34.59
|
$
|
64.00
|
||||||||||
Transportation
|
2.67
|
2.44
|
2.35
|
2.55
|
2.32
|
|||||||||||||||
Realized sales price, net of transportation
|
36.18
|
28.13
|
62.34
|
32.04
|
61.68
|
|||||||||||||||
Royalties
|
3.58
|
2.65
|
10.49
|
3.10
|
10.46
|
|||||||||||||||
Production expense
|
13.39
|
13.20
|
15.35
|
13.29
|
15.56
|
|||||||||||||||
Netback
|
$
|
19.21
|
$
|
12.28
|
$
|
36.50
|
$
|
15.65
|
$
|
35.66
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
(2) | Net of blending costs and excluding risk management activities. |
22
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
||||||||||||||||
Crude oil and NGLs ($/bbl) (1) (2)
|
||||||||||||||||||||
North America
|
$
|
50.96
|
$
|
35.22
|
$
|
84.10
|
$
|
42.52
|
$
|
81.06
|
||||||||||
North Sea
|
$
|
73.57
|
$
|
64.59
|
$
|
122.88
|
$
|
69.52
|
$
|
122.17
|
||||||||||
Offshore Africa
|
$
|
74.84
|
$
|
71.75
|
$
|
119.47
|
$
|
73.84
|
$
|
119.47
|
||||||||||
Company average
|
$
|
53.09
|
$
|
37.03
|
$
|
87.03
|
$
|
44.62
|
$
|
83.68
|
||||||||||
Natural gas ($/Mcf) (1) (2)
|
||||||||||||||||||||
North America
|
$
|
2.80
|
$
|
3.14
|
$
|
4.95
|
$
|
2.97
|
$
|
5.21
|
||||||||||
North Sea
|
$
|
9.54
|
$
|
10.18
|
$
|
6.38
|
$
|
9.84
|
$
|
6.19
|
||||||||||
Offshore Africa
|
$
|
10.49
|
$
|
11.70
|
$
|
12.25
|
$
|
11.07
|
$
|
12.22
|
||||||||||
Company average
|
$
|
3.06
|
$
|
3.38
|
$
|
5.06
|
$
|
3.22
|
$
|
5.32
|
||||||||||
Company average ($/BOE) (1) (2)
|
$
|
38.85
|
$
|
30.57
|
$
|
64.69
|
$
|
34.59
|
$
|
64.00
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
(2) | Net of blending costs and excluding risk management activities. |
Canadian Natural Resources Limited
|
23
|
(Quarterly Average)
|
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
|||||||||
Wellhead Price (1) (2)
|
||||||||||||
Light and medium crude oil and NGLs ($/bbl)
|
$
|
51.80
|
$
|
38.78
|
$
|
85.95
|
||||||
Pelican Lake heavy crude oil ($/bbl)
|
$
|
54.87
|
$
|
36.21
|
$
|
86.92
|
||||||
Primary heavy crude oil ($/bbl)
|
$
|
53.85
|
$
|
37.64
|
$
|
85.65
|
||||||
Bitumen (thermal oil) ($/bbl)
|
$
|
44.63
|
$
|
30.25
|
$
|
79.39
|
||||||
Natural gas ($/Mcf)
|
$
|
2.80
|
$
|
3.14
|
$
|
4.95
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
(2) | Net of blending costs and excluding risk management activities. |
24
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
||||||||||||||||
Crude oil and NGLs ($/bbl) (1)
|
||||||||||||||||||||
North America
|
$
|
6.40
|
$
|
4.02
|
$
|
16.79
|
$
|
5.12
|
$
|
15.85
|
||||||||||
North Sea
|
$
|
0.11
|
$
|
0.16
|
$
|
0.33
|
$
|
0.13
|
$
|
0.35
|
||||||||||
Offshore Africa
|
$
|
3.19
|
$
|
3.27
|
$
|
3.92
|
$
|
3.22
|
$
|
3.92
|
||||||||||
Company average
|
$
|
5.91
|
$
|
3.83
|
$
|
15.62
|
$
|
4.82
|
$
|
14.90
|
||||||||||
Natural gas ($/Mcf) (1)
|
||||||||||||||||||||
North America
|
$
|
0.05
|
$
|
0.12
|
$
|
0.39
|
$
|
0.08
|
$
|
0.47
|
||||||||||
Offshore Africa
|
$
|
0.48
|
$
|
0.54
|
$
|
1.89
|
$
|
0.51
|
$
|
1.97
|
||||||||||
Company average
|
$
|
0.05
|
$
|
0.12
|
$
|
0.41
|
$
|
0.08
|
$
|
0.49
|
||||||||||
Company average ($/BOE) (1)
|
$
|
3.58
|
$
|
2.65
|
$
|
10.49
|
$
|
3.10
|
$
|
10.46
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Canadian Natural Resources Limited
|
25
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
||||||||||||||||
Crude oil and NGLs ($/bbl) (1)
|
||||||||||||||||||||
North America
|
$
|
13.14
|
$
|
13.75
|
$
|
14.97
|
$
|
13.47
|
$
|
15.59
|
||||||||||
North Sea
|
$
|
60.61
|
$
|
65.23
|
$
|
79.21
|
$
|
62.69
|
$
|
77.46
|
||||||||||
Offshore Africa
|
$
|
43.88
|
$
|
15.46
|
$
|
58.41
|
$
|
34.71
|
$
|
58.41
|
||||||||||
Company average
|
$
|
17.01
|
$
|
16.10
|
$
|
19.33
|
$
|
16.53
|
$
|
19.26
|
||||||||||
Natural gas ($/Mcf) (1)
|
||||||||||||||||||||
North America
|
$
|
1.28
|
$
|
1.38
|
$
|
1.48
|
$
|
1.33
|
$
|
1.51
|
||||||||||
North Sea
|
$
|
6.47
|
$
|
3.89
|
$
|
6.12
|
$
|
5.27
|
$
|
5.95
|
||||||||||
Offshore Africa
|
$
|
1.42
|
$
|
2.80
|
$
|
3.28
|
$
|
2.09
|
$
|
3.45
|
||||||||||
Company average
|
$
|
1.39
|
$
|
1.44
|
$
|
1.52
|
$
|
1.42
|
$
|
1.56
|
||||||||||
Company average ($/BOE) (1)
|
$
|
13.39
|
$
|
13.20
|
$
|
15.35
|
$
|
13.29
|
$
|
15.56
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
26
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
($ millions, except per BOE amounts)
|
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
|||||||||||||||
Expense ($ millions)
|
$
|
1,158
|
$
|
1,213
|
$
|
1,099
|
$
|
2,371
|
$
|
1,978
|
||||||||||
$/BOE (1)
|
$
|
18.02
|
$
|
17.78
|
$
|
17.28
|
$
|
17.90
|
$
|
17.40
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
($ millions, except per BOE amounts)
|
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
|||||||||||||||
Expense ($ millions)
|
$
|
36
|
$
|
35
|
$
|
39
|
$
|
71
|
$
|
72
|
||||||||||
$/BOE (1)
|
$
|
0.55
|
$
|
0.52
|
$
|
0.59
|
$
|
0.53
|
$
|
0.63
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Canadian Natural Resources Limited
|
27
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
($/bbl)
|
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
|||||||||||||||
SCO sales price (1)
|
$
|
73.05
|
$
|
56.75
|
$
|
112.69
|
$
|
64.03
|
$
|
110.37
|
||||||||||
Bitumen value for royalty purposes (1) (2)
|
$
|
44.09
|
$
|
29.70
|
$
|
75.72
|
$
|
35.92
|
$
|
71.24
|
||||||||||
Bitumen royalties (1) (3)
|
$
|
0.99
|
$
|
1.01
|
$
|
6.77
|
$
|
1.00
|
$
|
5.95
|
||||||||||
Transportation
|
$
|
1.98
|
$
|
1.83
|
$
|
1.53
|
$
|
1.89
|
$
|
1.73
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
(2) | Calculated as the quarterly average of the bitumen valuation methodology price. |
(3) | Calculated based on actual bitumen royalties expensed during the period; divided by the corresponding SCO sales volumes. |
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
($ millions) |
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
|||||||||||||||
Cash production costs
|
$
|
321
|
$
|
346
|
$
|
404
|
$
|
667
|
$
|
816
|
||||||||||
Less: costs incurred during turnaround
periods
|
(45
|
)
|
–
|
–
|
(45
|
)
|
–
|
|||||||||||||
Adjusted cash production costs
|
$
|
276
|
$
|
346
|
$
|
404
|
$
|
622
|
$
|
816
|
||||||||||
Adjusted cash production costs, excluding
natural gas costs
|
$
|
260
|
$
|
326
|
$
|
372
|
$
|
586
|
$
|
747
|
||||||||||
Adjusted natural gas costs
|
16
|
20
|
32
|
36
|
69
|
|||||||||||||||
Adjusted cash production costs
|
$
|
276
|
$
|
346
|
$
|
404
|
$
|
622
|
$
|
816
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
($/bbl) (1)
|
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
|||||||||||||||
Adjusted cash production costs, excluding
natural gas costs
|
$
|
27.52
|
$
|
28.03
|
$
|
33.76
|
$
|
27.80
|
$
|
35.50
|
||||||||||
Adjusted natural gas costs
|
1.73
|
1.70
|
2.85
|
1.72
|
3.26
|
|||||||||||||||
Adjusted cash production costs
|
$
|
29.25
|
$
|
29.73
|
$
|
36.61
|
$
|
29.52
|
$
|
38.76
|
||||||||||
Sales (bbl/d)
|
103,388
|
129,433
|
121,091
|
116,339
|
116,325
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
28
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
($ millions, except per bbl amounts) |
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
|||||||||||||||
Depletion, depreciation and amortization
|
$
|
119
|
$
|
139
|
$
|
135
|
$
|
258
|
$
|
265
|
||||||||||
Less: depreciation incurred during
turnaround period
|
(5
|
)
|
–
|
–
|
(5
|
)
|
–
|
|||||||||||||
Adjusted depletion, depreciation and
amortization
|
$
|
114
|
$
|
139
|
$
|
135
|
$
|
253
|
$
|
265
|
||||||||||
$/bbl (1)
|
$
|
12.04
|
$
|
11.96
|
$
|
12.27
|
$
|
11.99
|
$
|
12.59
|
(1) | Amounts expressed on a per unit basis are based on sales volumes excluding turnaround periods. |
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
($ millions, except per bbl amounts) |
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
|||||||||||||||
Expense
|
$
|
7
|
$
|
8
|
$
|
11
|
$
|
15
|
$
|
23
|
||||||||||
$/bbl (1)
|
$
|
0.82
|
$
|
0.66
|
$
|
1.07
|
$
|
0.73
|
$
|
1.12
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Canadian Natural Resources Limited
|
29
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
($ millions) |
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
|||||||||||||||
Revenue
|
$
|
35
|
$
|
35
|
$
|
30
|
$
|
70
|
$
|
61
|
||||||||||
Production expense
|
9
|
9
|
10
|
18
|
19
|
|||||||||||||||
Midstream cash flow
|
26
|
26
|
20
|
52
|
42
|
|||||||||||||||
Depreciation
|
3
|
3
|
3
|
6
|
5
|
|||||||||||||||
Equity (gain) loss from investment
|
(3
|
)
|
15
|
(3
|
)
|
12
|
(2
|
)
|
||||||||||||
Segment earnings before taxes
|
$
|
26
|
$
|
8
|
$
|
20
|
$
|
34
|
$
|
39
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
($ millions, except per BOE amounts) |
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
|||||||||||||||
Expense
|
$
|
100
|
$
|
104
|
$
|
90
|
$
|
204
|
$
|
180
|
||||||||||
$/BOE (1)
|
$
|
1.35
|
$
|
1.31
|
$
|
1.21
|
$
|
1.33
|
$
|
1.34
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
30
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
($ millions)
|
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
|||||||||||||||
(Recovery) Expense
|
$
|
(79
|
)
|
$
|
64
|
$
|
189
|
$
|
(15
|
)
|
$
|
332
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
($ millions, except per BOE amounts and interest rates)
|
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
|||||||||||||||
Expense, gross
|
$
|
147
|
$
|
144
|
$
|
136
|
$
|
291
|
$
|
251
|
||||||||||
Less: capitalized interest
|
62
|
58
|
44
|
120
|
91
|
|||||||||||||||
Expense, net
|
$
|
85
|
$
|
86
|
$
|
92
|
$
|
171
|
$
|
160
|
||||||||||
$/BOE (1)
|
$
|
1.16
|
$
|
1.07
|
$
|
1.24
|
$
|
1.12
|
$
|
1.19
|
||||||||||
Average effective interest rate
|
3.8%
|
|
4.0%
|
|
3.9%
|
|
3.9%
|
|
4.0%
|
|
(1) | Amounts expressed on a per unit basis are based on sales volumes. |
Canadian Natural Resources Limited
|
31
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
||||||||||||||||
($ millions)
|
||||||||||||||||||||
Crude oil and NGLs financial instruments
|
$
|
(91
|
)
|
$
|
(117
|
)
|
$
|
–
|
$
|
(208
|
)
|
$
|
–
|
|||||||
Natural gas financial instruments
|
–
|
–
|
12
|
–
|
12
|
|||||||||||||||
Foreign currency contracts
|
22
|
(139
|
)
|
45
|
(117
|
)
|
(30
|
)
|
||||||||||||
Realized (gain) loss
|
(69
|
)
|
(256
|
)
|
57
|
(325
|
)
|
(18
|
)
|
|||||||||||
Crude oil and NGLs financial instruments
|
205
|
12
|
49
|
217
|
46
|
|||||||||||||||
Natural gas financial instruments
|
–
|
–
|
(24
|
)
|
–
|
21
|
||||||||||||||
Foreign currency contracts
|
10
|
2
|
29
|
12
|
36
|
|||||||||||||||
Unrealized loss
|
215
|
14
|
54
|
229
|
103
|
|||||||||||||||
Net loss (gain)
|
$
|
146
|
$
|
(242
|
)
|
$
|
111
|
$
|
(96
|
)
|
$
|
85
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
($ millions)
|
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
|||||||||||||||
Net realized (gain) loss
|
$
|
(11
|
)
|
$
|
(53
|
)
|
$
|
31
|
$
|
(64
|
)
|
$
|
30
|
|||||||
Net unrealized (gain) loss (1)
|
(76
|
)
|
413
|
(153
|
)
|
337
|
(35
|
)
|
||||||||||||
Net (gain) loss
|
$
|
(87
|
)
|
$
|
360
|
$
|
(122
|
)
|
$
|
273
|
$
|
(5
|
)
|
(1) | Amounts are reported net of the hedging effect of cross currency swaps. |
32
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
($ millions, except income tax rates)
|
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
|||||||||||||||
North America (1)
|
$
|
79
|
$
|
8
|
$
|
225
|
$
|
87
|
$
|
417
|
||||||||||
North Sea
|
(19
|
)
|
(64
|
)
|
(44
|
)
|
(83
|
)
|
(59
|
)
|
||||||||||
Offshore Africa
|
5
|
2
|
10
|
7
|
14
|
|||||||||||||||
PRT recovery – North Sea
|
(72
|
)
|
(54
|
)
|
(12
|
)
|
(126
|
)
|
(73
|
)
|
||||||||||
Other taxes
|
4
|
3
|
6
|
7
|
12
|
|||||||||||||||
Current income tax (recovery) expense
|
(3
|
)
|
(105
|
)
|
185
|
(108
|
)
|
311
|
||||||||||||
Deferred income tax expense (recovery)
|
498
|
(289
|
)
|
178
|
209
|
269
|
||||||||||||||
Deferred PRT expense – North Sea
|
30
|
7
|
11
|
37
|
77
|
|||||||||||||||
Deferred income tax expense (recovery)
|
528
|
(282
|
)
|
189
|
246
|
346
|
||||||||||||||
$
|
525
|
$
|
(387
|
)
|
$
|
374
|
$
|
138
|
$
|
657
|
||||||||||
Income tax rate and other legislative changes (2) (3)
|
(579
|
)
|
228
|
–
|
(351
|
)
|
–
|
|||||||||||||
$
|
(54
|
)
|
$
|
(159
|
)
|
$
|
374
|
$
|
(213
|
)
|
$
|
657
|
||||||||
Effective income tax rate on adjusted net earnings from operations (4)
|
17.0%
|
|
105.8%
|
|
24.8%
|
|
64.0%
|
|
24.2%
|
|
(1) | Includes North America Exploration and Production, Midstream, and Oil Sands Mining and Upgrading segments. |
(2) | During the second quarter of 2015, the Alberta government enacted legislation that increased the provincial corporate income tax rate from 10% to 12% effective July 1, 2015. As a result of this income tax rate increase, the Company’s deferred income tax liability was increased by $579 million. |
(3) | During the first quarter of 2015, the UK government enacted tax rate reductions to the supplementary charge on oil and gas profits and the Petroleum Revenue Tax (“PRT”), and replaced the Brownfield Allowance with a new Investment Allowance, resulting in a decrease in the Company’s deferred income tax liability of $228 million. |
(4) | Excludes the impact of current and deferred PRT expense and other current income tax expense. |
Canadian Natural Resources Limited
|
33
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
($ millions)
|
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
|||||||||||||||
Exploration and Evaluation
|
||||||||||||||||||||
Net expenditures (2)
|
$
|
29
|
$
|
46
|
$
|
884
|
$
|
75
|
$
|
1,001
|
||||||||||
Property, Plant and Equipment
|
||||||||||||||||||||
Net property acquisitions (2)
|
51
|
11
|
2,746
|
62
|
2,742
|
|||||||||||||||
Well drilling, completion and equipping
|
199
|
292
|
441
|
491
|
1,082
|
|||||||||||||||
Production and related facilities
|
249
|
314
|
429
|
563
|
844
|
|||||||||||||||
Capitalized interest and other (3)
|
27
|
26
|
21
|
53
|
44
|
|||||||||||||||
Net expenditures
|
526
|
643
|
3,637
|
1,169
|
4,712
|
|||||||||||||||
Total Exploration and Production
|
555
|
689
|
4,521
|
1,244
|
5,713
|
|||||||||||||||
Oil Sands Mining and Upgrading
|
||||||||||||||||||||
Horizon Phase 2/3 construction costs
|
535
|
406
|
649
|
941
|
1,093
|
|||||||||||||||
Sustaining capital
|
94
|
88
|
87
|
182
|
147
|
|||||||||||||||
Turnaround costs
|
6
|
4
|
4
|
10
|
6
|
|||||||||||||||
Capitalized interest and other (3)
|
43
|
71
|
84
|
114
|
157
|
|||||||||||||||
Total Oil Sands Mining and Upgrading
|
678
|
569
|
824
|
1,247
|
1,403
|
|||||||||||||||
Midstream
|
1
|
3
|
26
|
4
|
51
|
|||||||||||||||
Abandonments (4)
|
56
|
144
|
76
|
200
|
163
|
|||||||||||||||
Head office
|
7
|
7
|
9
|
14
|
19
|
|||||||||||||||
Total net capital expenditures
|
$
|
1,297
|
$
|
1,412
|
$
|
5,456
|
$
|
2,709
|
$
|
7,349
|
||||||||||
By segment
|
||||||||||||||||||||
North America (2)
|
$
|
307
|
$
|
501
|
$
|
4,387
|
$
|
808
|
$
|
5,474
|
||||||||||
North Sea
|
93
|
62
|
107
|
155
|
195
|
|||||||||||||||
Offshore Africa
|
155
|
126
|
27
|
281
|
44
|
|||||||||||||||
Oil Sands Mining and Upgrading
|
678
|
569
|
824
|
1,247
|
1,403
|
|||||||||||||||
Midstream
|
1
|
3
|
26
|
4
|
51
|
|||||||||||||||
Abandonments (4)
|
56
|
144
|
76
|
200
|
163
|
|||||||||||||||
Head office
|
7
|
7
|
9
|
14
|
19
|
|||||||||||||||
Total
|
$
|
1,297
|
$
|
1,412
|
$
|
5,456
|
$
|
2,709
|
$
|
7,349
|
(1)
|
Net capital expenditures exclude adjustments related to differences between carrying amounts and tax values, and other fair value adjustments.
|
(2)
|
Includes Business Combinations.
|
(3)
|
Capitalized interest and other includes expenditures related to land acquisition and retention, seismic, and other adjustments.
|
(4) | Abandonments represent expenditures to settle asset retirement obligations and have been reflected as capital expenditures in this table. |
34
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||||||
(number of wells)
|
Jun 30
2015 |
Mar 31
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
|||||||||||||||
Net successful natural gas wells
|
2
|
9
|
13
|
11
|
38
|
|||||||||||||||
Net successful crude oil wells (1)
|
5
|
42
|
154
|
47
|
425
|
|||||||||||||||
Dry wells
|
–
|
2
|
2
|
2
|
5
|
|||||||||||||||
Stratigraphic test / service wells
|
6
|
86
|
22
|
92
|
352
|
|||||||||||||||
Total
|
13
|
139
|
191
|
152
|
820
|
|||||||||||||||
Success rate (excluding stratigraphic test /
service wells)
|
100%
|
|
96%
|
|
99%
|
|
97%
|
|
99%
|
|
(1) | Includes bitumen wells. |
Canadian Natural Resources Limited
|
35
|
36
|
Canadian Natural Resources Limited
|
($ millions, except ratios)
|
Jun 30
2015 |
Mar 31
2015 |
Dec 31
2014 |
Jun 30
2014 |
||||||||||||
Working capital (deficit) (1)
|
$
|
261
|
$
|
(13
|
)
|
$
|
(673
|
)
|
$
|
(991
|
)
|
|||||
Long-term debt (2) (3)
|
$
|
15,983
|
$
|
15,689
|
$
|
14,002
|
$
|
13,437
|
||||||||
Share capital
|
$
|
4,532
|
$
|
4,474
|
$
|
4,432
|
$
|
4,321
|
||||||||
Retained earnings
|
23,248
|
23,905
|
24,408
|
22,856
|
||||||||||||
Accumulated other comprehensive income
(loss)
|
(7
|
)
|
36
|
51
|
46
|
|||||||||||
Shareholders’ equity
|
$
|
27,773
|
$
|
28,415
|
$
|
28,891
|
$
|
27,223
|
||||||||
Debt to book capitalization (3) (4)
|
37%
|
|
36%
|
|
33%
|
|
33%
|
|
||||||||
Debt to market capitalization (3) (5)
|
30%
|
|
27%
|
|
26%
|
|
20%
|
|
||||||||
After-tax return on average common
shareholders’ equity (6) |
6%
|
|
11%
|
|
14%
|
|
13%
|
|
||||||||
After-tax return on average capital
employed (3) (7) |
4%
|
|
8%
|
|
10%
|
|
10%
|
|
(1) | Calculated as current assets less current liabilities, excluding the current portion of long-term debt. |
(2) | Includes the current portion of long-term debt. |
(3) | Long-term debt is stated at its carrying value, net of fair value adjustments, original issue discounts and premiums, and transaction costs. |
(4) | Calculated as current and long-term debt; divided by the book value of common shareholders’ equity plus current and long-term debt. |
(5) | Calculated as current and long-term debt; divided by the market value of common shareholders’ equity plus current and long-term debt. |
(6) | Calculated as net earnings for the twelve month trailing period; as a percentage of average common shareholders’ equity for the period. |
(7) | Calculated as net earnings plus after-tax interest and other financing expense for the twelve month trailing period; as a percentage of average capital employed for the period. |
§ | Monitoring cash flow from operations, which is the primary source of funds; |
§ | Actively managing the allocation of maintenance and growth capital to ensure it is expended in a prudent and appropriate manner with flexibility to adjust to market conditions. In response to declining commodity prices in late 2014 and the first half of 2015, the Company continues to exercise its capital flexibility to address commodity price volatility and its impact on operating expenditures, capital commitments and long-term debt; |
§ | Reviewing the Company’s borrowing capacity: |
— | During the second quarter of 2015, the Company issued $500 million of series 2 medium-term notes, due August 2020, through the reopening of its previously issued 2.89% notes. In addition, the $1,500 million revolving syndicated credit facility was increased to $2,425 million and the maturity date was extended to June 2019 from June 2016. The $3,000 million revolving syndicated credit facility was reduced to $2,425 million and the maturity date was extended to June 2020 from June 2017. As a result, the Company’s available liquidity increased by $350 million; |
— | The Company’s borrowings under its US commercial paper program are authorized up to a maximum of US$2,500 million. The Company reserves capacity under its bank credit facilities for amounts outstanding under the US commercial paper program; |
Canadian Natural Resources Limited
|
37
|
— | During the first quarter of 2015, the Company extended its existing $1,000 million non-revolving term credit facility to January 2017. In addition, the Company entered into a new $1,500 million non-revolving term credit facility maturing April 2018. Both facilities were fully drawn at June 30, 2015; |
§ | Reviewing bank credit facilities and public debt indentures to ensure they are in compliance with applicable covenant packages. All of the Company’s credit facilities are now subject to a revised financial covenant that the Consolidated Debt to Capitalization Ratio, as defined in the credit agreements, shall not be more than 0.65 to 1.0; and |
§ | Monitoring exposure to individual customers, contractors, suppliers and joint venture partners on a regular basis and when appropriate, ensuring parental guarantees or letters of credit are in place to minimize the impact in the event of a default. |
38
|
Canadian Natural Resources Limited
|
($ millions)
|
Remaining
2015
|
2016
|
2017
|
2018
|
2019
|
Thereafter
|
||||||||||||||||||
Product transportation and
pipeline
|
$
|
225
|
$
|
371
|
$
|
325
|
$
|
283
|
$
|
246
|
$
|
1,519
|
||||||||||||
Offshore equipment operating
leases and offshore drilling
|
$
|
214
|
$
|
136
|
$
|
84
|
$
|
64
|
$
|
20
|
$
|
–
|
||||||||||||
Long-term debt (1)
|
$
|
623
|
$
|
936
|
$
|
2,371
|
$
|
2,749
|
$
|
1,000
|
$
|
8,384
|
||||||||||||
Interest and other financing
expense (2)
|
$
|
306
|
$
|
604
|
$
|
524
|
$
|
442
|
$
|
406
|
$
|
4,535
|
||||||||||||
Office leases
|
$
|
21
|
$
|
42
|
$
|
45
|
$
|
46
|
$
|
48
|
$
|
293
|
||||||||||||
Other
|
$
|
85
|
$
|
111
|
$
|
24
|
$
|
34
|
$
|
1
|
$
|
–
|
(1) | Long-term debt represents principal repayments only and does not reflect original issue discounts and premiums or transaction costs. |
(2) | Interest and other financing expense amounts represent the scheduled fixed rate and variable rate cash interest payments related to long-term debt. Interest on variable rate long‑term debt was estimated based upon prevailing interest rates and foreign exchange rates as at June 30, 2015. |
Canadian Natural Resources Limited
|
39
|
As at
(millions of Canadian dollars, unaudited) |
Note
|
Jun 30
2015 |
Dec 31
2014 |
||||||||
ASSETS
|
|||||||||||
Current assets
|
|||||||||||
Cash and cash equivalents
|
$
|
32
|
$
|
25
|
|||||||
Accounts receivable
|
1,488
|
1,889
|
|||||||||
Current income taxes
|
653
|
228
|
|||||||||
Inventory
|
733
|
665
|
|||||||||
Prepaids and other
|
290
|
172
|
|||||||||
Current portion of other long-term assets
|
4
|
364
|
510
|
||||||||
3,560
|
3,489
|
||||||||||
Exploration and evaluation assets
|
2
|
3,477
|
3,557
|
||||||||
Property, plant and equipment
|
3
|
52,677
|
52,480
|
||||||||
Other long-term assets
|
4
|
829
|
674
|
||||||||
$
|
60,543
|
$
|
60,200
|
||||||||
LIABILITIES
|
|||||||||||
Current liabilities
|
|||||||||||
Accounts payable
|
$
|
543
|
$
|
564
|
|||||||
Accrued liabilities
|
2,532
|
3,279
|
|||||||||
Current portion of long-term debt
|
5
|
1,246
|
980
|
||||||||
Current portion of other long-term liabilities
|
6
|
224
|
319
|
||||||||
4,545
|
5,142
|
||||||||||
Long-term debt
|
5
|
14,737
|
13,022
|
||||||||
Other long-term liabilities
|
6
|
4,211
|
4,175
|
||||||||
Deferred income taxes
|
9,277
|
8,970
|
|||||||||
32,770
|
31,309
|
||||||||||
SHAREHOLDERS’ EQUITY
|
|||||||||||
Share capital
|
8
|
4,532
|
4,432
|
||||||||
Retained earnings
|
23,248
|
24,408
|
|||||||||
Accumulated other comprehensive income (loss)
|
9
|
(7
|
)
|
51
|
|||||||
27,773
|
28,891
|
||||||||||
$
|
60,543
|
$
|
60,200
|
40
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Six Months Ended
|
||||||||||||||||||
(millions of Canadian dollars, except per
common share amounts, unaudited)
|
Note
|
Jun 30
2015
|
Jun 30
2014
|
Jun 30
2015
|
Jun 30
2014 |
||||||||||||||
Product sales
|
$
|
3,662
|
$
|
6,113
|
$
|
6,888
|
$
|
11,081
|
|||||||||||
Less: royalties
|
(240
|
)
|
(742
|
)
|
(432
|
)
|
(1,314
|
)
|
|||||||||||
Revenue
|
3,422
|
5,371
|
6,456
|
9,767
|
|||||||||||||||
Expenses
|
|||||||||||||||||||
Production
|
1,188
|
1,388
|
2,441
|
2,599
|
|||||||||||||||
Transportation and blending
|
629
|
895
|
1,264
|
1,726
|
|||||||||||||||
Depletion, depreciation and amortization
|
3
|
1,280
|
1,237
|
2,635
|
2,248
|
||||||||||||||
Administration
|
100
|
90
|
204
|
180
|
|||||||||||||||
Share-based compensation
|
6
|
(79
|
)
|
189
|
(15
|
)
|
332
|
||||||||||||
Asset retirement obligation accretion
|
6
|
43
|
50
|
86
|
95
|
||||||||||||||
Interest and other financing expense
|
85
|
92
|
171
|
160
|
|||||||||||||||
Risk management activities
|
12
|
146
|
111
|
(96
|
)
|
85
|
|||||||||||||
Foreign exchange (gain) loss
|
(87
|
)
|
(122
|
)
|
273
|
(5
|
)
|
||||||||||||
Equity (gain) loss from investment
|
4
|
(3
|
)
|
(3
|
)
|
12
|
(2
|
)
|
|||||||||||
3,302
|
3,927
|
6,975
|
7,418
|
||||||||||||||||
Earnings (loss) before taxes
|
120
|
1,444
|
(519
|
)
|
2,349
|
||||||||||||||
Current income tax (recovery) expense
|
7
|
(3
|
)
|
185
|
(108
|
)
|
311
|
||||||||||||
Deferred income tax expense
|
7
|
528
|
189
|
246
|
346
|
||||||||||||||
Net earnings (loss)
|
$
|
(405
|
)
|
$
|
1,070
|
$
|
(657
|
)
|
$
|
1,692
|
|||||||||
Net earnings (loss) per common share
|
|||||||||||||||||||
Basic
|
11
|
$
|
(0.37
|
)
|
$
|
0.98
|
$
|
(0.60
|
)
|
$
|
1.55
|
||||||||
Diluted
|
11
|
$
|
(0.37
|
)
|
$
|
0.97
|
$
|
(0.60
|
)
|
$
|
1.54
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
(millions of Canadian dollars, unaudited)
|
Jun 30
2015
|
Jun 30
2014
|
Jun 30
2015
|
Jun 30
2014 |
||||||||||||
Net earnings (loss)
|
$
|
(405
|
)
|
$
|
1,070
|
$
|
(657
|
)
|
$
|
1,692
|
||||||
Items that may be reclassified subsequently
to net earnings |
||||||||||||||||
Net change in derivative financial instruments
designated as cash flow hedges
|
||||||||||||||||
Unrealized income (loss) during the period, net of taxes of
$5 million (2014 – $nil) – three months ended;
$6 million (2014 – $nil) – six months ended
|
(34
|
)
|
–
|
(43
|
)
|
1
|
||||||||||
Reclassification to net earnings (loss), net of taxes of
$1 million (2014 – $nil) – three months ended;
$1 million (2014 – $nil) – six months ended
|
(4
|
)
|
1
|
(6
|
)
|
4
|
||||||||||
(38
|
)
|
1
|
(49
|
)
|
5
|
|||||||||||
Foreign currency translation adjustment
|
||||||||||||||||
Translation of net investment
|
(5
|
)
|
1
|
(9
|
)
|
(1
|
)
|
|||||||||
Other comprehensive income (loss), net of taxes
|
(43
|
)
|
2
|
(58
|
)
|
4
|
||||||||||
Comprehensive income (loss)
|
$
|
(448
|
)
|
$
|
1,072
|
$
|
(715
|
)
|
$
|
1,696
|
Canadian Natural Resources Limited
|
41
|
Six Months Ended
|
|||||||||||
(millions of Canadian dollars, unaudited)
|
Note
|
Jun 30
2015
|
Jun 30
2014
|
||||||||
Share capital
|
8
|
||||||||||
Balance – beginning of period
|
$
|
4,432
|
$
|
3,854
|
|||||||
Issued upon exercise of stock options
|
83
|
385
|
|||||||||
Previously recognized liability on stock options exercised for
common shares |
17
|
103
|
|||||||||
Purchase of common shares under Normal Course Issuer Bid
|
–
|
(21
|
)
|
||||||||
Balance – end of period
|
4,532
|
4,321
|
|||||||||
Retained earnings
|
|||||||||||
Balance – beginning of period
|
24,408
|
21,876
|
|||||||||
Net earnings (loss)
|
(657
|
)
|
1,692
|
||||||||
Purchase of common shares under Normal Course Issuer Bid
|
8
|
–
|
(220
|
)
|
|||||||
Dividends on common shares
|
8
|
(503
|
)
|
(492
|
)
|
||||||
Balance – end of period
|
23,248
|
22,856
|
|||||||||
Accumulated other comprehensive income (loss)
|
9
|
||||||||||
Balance – beginning of period
|
51
|
42
|
|||||||||
Other comprehensive income (loss), net of taxes
|
(58
|
)
|
4
|
||||||||
Balance – end of period
|
(7
|
)
|
46
|
||||||||
Shareholders’ equity
|
$
|
27,773
|
$
|
27,223
|
42
|
Canadian Natural Resources Limited
|
Three Months Ended |
Six Months Ended
|
|||||||||||||||
(millions of Canadian dollars, unaudited)
|
Jun 30
2015
|
Jun 30
2014
|
Jun 30
2015
|
Jun 30
2014
|
||||||||||||
Operating activities
|
||||||||||||||||
Net earnings (loss)
|
$
|
(405
|
)
|
$
|
1,070
|
$
|
(657
|
)
|
$
|
1,692
|
||||||
Non-cash items
|
||||||||||||||||
Depletion, depreciation and amortization
|
1,280
|
1,237
|
2,635
|
2,248
|
||||||||||||
Share-based compensation
|
(79
|
)
|
189
|
(15
|
)
|
332
|
||||||||||
Asset retirement obligation accretion
|
43
|
50
|
86
|
95
|
||||||||||||
Unrealized risk management loss
|
215
|
54
|
229
|
103
|
||||||||||||
Unrealized foreign exchange (gain) loss
|
(76
|
)
|
(153
|
)
|
337
|
(35
|
)
|
|||||||||
Equity (gain) loss from investment
|
(3
|
)
|
(3
|
)
|
12
|
(2
|
)
|
|||||||||
Deferred income tax expense
|
528
|
189
|
246
|
346
|
||||||||||||
Other
|
20
|
20
|
62
|
51
|
||||||||||||
Abandonment expenditures
|
(56
|
)
|
(76
|
)
|
(200
|
)
|
(163
|
)
|
||||||||
Net change in non-cash working capital
|
(182
|
)
|
(120
|
)
|
(196
|
)
|
(857
|
)
|
||||||||
1,285
|
2,457
|
2,539
|
3,810
|
|||||||||||||
Financing activities
|
||||||||||||||||
Issue of bank credit facilities and commercial paper, net
|
334
|
2,369
|
1,211
|
1,708
|
||||||||||||
Issue of medium-term notes, net
|
107
|
992
|
107
|
992
|
||||||||||||
Issue of US dollar debt securities, net
|
–
|
–
|
–
|
1,100
|
||||||||||||
Issue of common shares on exercise of
stock options
|
48
|
190
|
83
|
385
|
||||||||||||
Purchase of common shares under Normal
Course Issuer Bid
|
–
|
(176
|
)
|
–
|
(241
|
)
|
||||||||||
Dividends on common shares
|
(251
|
)
|
(246
|
)
|
(496
|
)
|
(463
|
)
|
||||||||
Net change in non-cash working capital
|
(27
|
)
|
(6
|
)
|
(40
|
)
|
(11
|
)
|
||||||||
211
|
3,123
|
865
|
3,470
|
|||||||||||||
Investing activities
|
||||||||||||||||
Net expenditures on exploration and
evaluation assets
|
(29
|
)
|
(884
|
)
|
(75
|
)
|
(1,001
|
)
|
||||||||
Net expenditures on property, plant and
equipment
|
(1,212
|
)
|
(4,496
|
)
|
(2,434
|
)
|
(6,185
|
)
|
||||||||
Investment in other long-term assets
|
–
|
(113
|
)
|
(112
|
)
|
(113
|
)
|
|||||||||
Net change in non-cash working capital
|
(257
|
)
|
(75
|
)
|
(776
|
)
|
34
|
|||||||||
(1,498
|
)
|
(5,568
|
)
|
(3,397
|
)
|
(7,265
|
)
|
|||||||||
(Decrease) increase in cash and cash
equivalents
|
(2
|
)
|
12
|
7
|
15
|
|||||||||||
Cash and cash equivalents –
beginning of period
|
34
|
19
|
25
|
16
|
||||||||||||
Cash and cash equivalents –
end of period
|
$
|
32
|
$
|
31
|
$
|
32
|
$
|
31
|
||||||||
Interest paid
|
$
|
119
|
$
|
110
|
$
|
275
|
$
|
245
|
||||||||
Income taxes paid
|
$
|
55
|
$
|
147
|
$
|
264
|
$
|
602
|
Canadian Natural Resources Limited
|
43
|
Exploration and Production
|
Oil Sands
Mining and Upgrading
|
Total
|
||||||||||||||||||
North America
|
North Sea
|
Offshore Africa
|
||||||||||||||||||
Cost
|
||||||||||||||||||||
At December 31, 2014
|
$
|
3,426
|
$
|
–
|
$
|
131
|
$
|
–
|
$
|
3,557
|
||||||||||
Additions
|
52
|
–
|
23
|
–
|
75
|
|||||||||||||||
Transfers to property, plant and equipment
|
(160
|
)
|
–
|
–
|
–
|
(160
|
)
|
|||||||||||||
Foreign exchange adjustments
|
–
|
–
|
5
|
–
|
5
|
|||||||||||||||
At June 30, 2015
|
$
|
3,318
|
$
|
–
|
$
|
159
|
$
|
–
|
$
|
3,477
|
44
|
Canadian Natural Resources Limited
|
Exploration and Production
|
Oil Sands
Mining and Upgrading
|
Midstream
|
Head
Office
|
Total
|
||||||||||||||||||||||||
North America
|
North Sea
|
Offshore
Africa |
||||||||||||||||||||||||||
Cost
|
||||||||||||||||||||||||||||
At December 31, 2014
|
$
|
60,606
|
$
|
6,182
|
$
|
3,858
|
$
|
21,948
|
$
|
570
|
$
|
352
|
$
|
93,516
|
||||||||||||||
Additions
|
790
|
153
|
258
|
1,247
|
4
|
14
|
2,466
|
|||||||||||||||||||||
Transfers from E&E assets
|
160
|
–
|
–
|
–
|
–
|
–
|
160
|
|||||||||||||||||||||
Disposals/derecognitions
|
(189
|
)
|
–
|
–
|
(49
|
)
|
–
|
–
|
(238
|
)
|
||||||||||||||||||
Foreign exchange adjustments and other
|
–
|
468
|
293
|
–
|
–
|
–
|
761
|
|||||||||||||||||||||
At June 30, 2015
|
$
|
61,367
|
$
|
6,803
|
$
|
4,409
|
$
|
23,146
|
$
|
574
|
$
|
366
|
$
|
96,665
|
||||||||||||||
Accumulated depletion and depreciation
|
||||||||||||||||||||||||||||
At December 31, 2014
|
$
|
31,886
|
$
|
4,049
|
$
|
2,890
|
$
|
1,864
|
$
|
120
|
$
|
227
|
$
|
41,036
|
||||||||||||||
Expense
|
2,112
|
184
|
61
|
258
|
6
|
14
|
2,635
|
|||||||||||||||||||||
Disposals/derecognitions
|
(189
|
)
|
–
|
–
|
(49
|
)
|
–
|
–
|
(238
|
)
|
||||||||||||||||||
Foreign exchange adjustments and other
|
3
|
309
|
237
|
6
|
–
|
–
|
555
|
|||||||||||||||||||||
At June 30, 2015
|
$
|
33,812
|
$
|
4,542
|
$
|
3,188
|
$
|
2,079
|
$
|
126
|
$
|
241
|
$
|
43,988
|
||||||||||||||
Net book value
– at June 30, 2015
|
$
|
27,555
|
$
|
2,261
|
$
|
1,221
|
$
|
21,067
|
$
|
448
|
$
|
125
|
$
|
52,677
|
||||||||||||||
– at December 31, 2014
|
$
|
28,720
|
$
|
2,133
|
$
|
968
|
$
|
20,084
|
$
|
450
|
$
|
125
|
$
|
52,480
|
Project costs not subject to depletion and depreciation
|
Jun 30
2015
|
Dec 31
2014
|
||||||
Horizon
|
$
|
6,389
|
$
|
5,492
|
||||
Kirby Thermal Oil Sands – North
|
$
|
760
|
$
|
681
|
Canadian Natural Resources Limited
|
45
|
Jun 30
2015
|
Dec 31
2014
|
|||||||
Investment in North West Redwater Partnership
|
$
|
286
|
$
|
298
|
||||
North West Redwater Partnership subordinated debt (1)
|
243
|
120
|
||||||
Risk Management (note 12)
|
569
|
599
|
||||||
Other
|
95
|
167
|
||||||
1,193
|
1,184
|
|||||||
Less: current portion
|
364
|
510
|
||||||
$
|
829
|
$
|
674
|
(1) | Includes accrued interest. |
46
|
Canadian Natural Resources Limited
|
Jun 30
2015
|
Dec 31
2014 |
|||||||
Canadian dollar denominated debt, unsecured
|
||||||||
Bank credit facilities
|
$
|
3,129
|
$
|
2,404
|
||||
Medium-term notes
|
2,500
|
2,400
|
||||||
5,629
|
4,804
|
|||||||
US dollar denominated debt, unsecured
|
||||||||
Bank credit facilities (June 30, 2015 – US$365 million;
December 31, 2014 – $nil)
|
$
|
455
|
$
|
–
|
||||
Commercial paper (US$500 million)
|
623
|
580
|
||||||
US dollar debt securities (US$7,500 million)
|
9,356
|
8,701
|
||||||
10,434
|
9,281
|
|||||||
Long-term debt before transaction costs and original issue discounts, net
|
16,063
|
14,085
|
||||||
Less: original issue discounts, net (1)
|
(10
|
)
|
(21
|
)
|
||||
Less: transaction costs (1) (2)
|
(70
|
)
|
(62
|
)
|
||||
15,983
|
14,002
|
|||||||
Less: current portion of commercial paper
|
623
|
580
|
||||||
current portion of long-term debt (1) (2)
|
623
|
400
|
||||||
$
|
14,737
|
$
|
13,022
|
(1) | The Company has included unamortized original issue discounts and premiums, and directly attributable transaction costs in the carrying amount of the outstanding debt. |
(2) | Transaction costs primarily represent underwriting commissions charged as a percentage of the related debt offerings, as well as legal, rating agency and other professional fees. |
§ | a $100 million demand credit facility; |
§ | a $1,000 million non-revolving term credit facility maturing January 2017; |
§ | a $1,500 million non-revolving term credit facility maturing April 2018; |
§ | a $2,425 million revolving syndicated credit facility maturing June 2019; |
§ | a $2,425 million revolving syndicated credit facility maturing June 2020; and |
§ | a £15 million demand credit facility related to the Company’s North Sea operations. |
Canadian Natural Resources Limited
|
47
|
Jun 30
2015 |
Dec 31
2014 |
|||||||
Asset retirement obligations
|
$
|
4,243
|
$
|
4,221
|
||||
Share-based compensation
|
168
|
203
|
||||||
Other
|
24
|
70
|
||||||
4,435
|
4,494
|
|||||||
Less: current portion
|
224
|
319
|
||||||
$
|
4,211
|
$
|
4,175
|
48
|
Canadian Natural Resources Limited
|
Jun 30
2015 |
Dec 31
2014 |
|||||||
Balance – beginning of period
|
$
|
4,221
|
$
|
4,162
|
||||
Liabilities incurred
|
3
|
41
|
||||||
Liabilities acquired
|
29
|
404
|
||||||
Liabilities settled
|
(200
|
)
|
(346
|
)
|
||||
Asset retirement obligation accretion
|
86
|
193
|
||||||
Revision of cost, inflation rates and timing estimates
|
–
|
(907
|
)
|
|||||
Change in discount rate
|
–
|
558
|
||||||
Foreign exchange adjustments
|
104
|
116
|
||||||
Balance – end of period
|
4,243
|
4,221
|
||||||
Less: current portion
|
103
|
121
|
||||||
$
|
4,140
|
$
|
4,100
|
Jun 30
2015 |
Dec 31
2014 |
|||||||
Balance – beginning of period
|
$
|
203
|
$
|
260
|
||||
Share-based compensation (recovery) expense
|
(15
|
)
|
66
|
|||||
Cash payment for stock options surrendered
|
(1
|
)
|
(8
|
)
|
||||
Transferred to common shares
|
(17
|
)
|
(129
|
)
|
||||
(Recovered from) capitalized to Oil Sands Mining and Upgrading
|
(2
|
)
|
14
|
|||||
Balance – end of period
|
168
|
203
|
||||||
Less: current portion
|
121
|
158
|
||||||
$
|
47
|
$
|
45
|
Canadian Natural Resources Limited
|
49
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
Jun 30
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
|||||||||||||
Current corporate income tax expense – North
America
|
$
|
79
|
$
|
225
|
$
|
87
|
$
|
417
|
||||||||
Current corporate income tax recovery – North Sea
|
(19
|
)
|
(44
|
)
|
(83
|
)
|
(59
|
)
|
||||||||
Current corporate income tax expense – Offshore
Africa
|
5
|
10
|
7
|
14
|
||||||||||||
Current PRT (1) recovery – North Sea
|
(72
|
)
|
(12
|
)
|
(126
|
)
|
(73
|
)
|
||||||||
Other taxes
|
4
|
6
|
7
|
12
|
||||||||||||
Current income tax (recovery) expense
|
(3
|
)
|
185
|
(108
|
)
|
311
|
||||||||||
Deferred corporate income tax expense
|
498
|
178
|
209
|
269
|
||||||||||||
Deferred PRT (1) expense – North Sea
|
30
|
11
|
37
|
77
|
||||||||||||
Deferred income tax expense
|
528
|
189
|
246
|
346
|
||||||||||||
Income tax expense
|
$
|
525
|
$
|
374
|
$
|
138
|
$
|
657
|
(1) | Petroleum Revenue Tax. |
Six Months Ended Jun 30, 2015
|
||||||||
Issued common shares
|
Number of shares (thousands)
|
Amount
|
||||||
Balance – beginning of period
|
1,091,837
|
$
|
4,432
|
|||||
Issued upon exercise of stock options
|
2,541
|
83
|
||||||
Previously recognized liability on stock options exercised for
common shares
|
–
|
17
|
||||||
Balance – end of period
|
1,094,378
|
$
|
4,532
|
50
|
Canadian Natural Resources Limited
|
Six Months Ended Jun 30, 2015
|
||||||||
Stock options (thousands)
|
Weighted average
exercise price |
|||||||
Outstanding – beginning of period
|
71,708
|
$
|
35.60
|
|||||
Granted
|
4,773
|
$
|
33.25
|
|||||
Surrendered for cash settlement
|
(165
|
)
|
$
|
33.43
|
||||
Exercised for common shares
|
(2,541
|
)
|
$
|
32.73
|
||||
Forfeited
|
(6,060
|
)
|
$
|
35.00
|
||||
Outstanding – end of period
|
67,715
|
$
|
35.60
|
|||||
Exercisable – end of period
|
19,527
|
$
|
36.82
|
Jun 30
2015
|
Jun 30
2014
|
|||||||
Derivative financial instruments designated as cash flow hedges
|
$
|
45
|
$
|
86
|
||||
Foreign currency translation adjustment
|
(52
|
)
|
(40
|
)
|
||||
$
|
(7
|
)
|
$
|
46
|
Canadian Natural Resources Limited
|
51
|
Jun 30
2015 |
Dec 31
2014 |
|||||||
Long-term debt (1)
|
$
|
15,983
|
$
|
14,002
|
||||
Total shareholders’ equity
|
$
|
27,773
|
$
|
28,891
|
||||
Debt to book capitalization
|
37%
|
|
33%
|
|
(1) | Includes the current portion of long-term debt. |
Three Months Ended |
Six Months Ended
|
|||||||||||||||
Jun 30
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
|||||||||||||
Weighted average common shares outstanding
– basic (thousands of shares) |
1,094,143
|
1,093,522
|
1,093,252
|
1,091,719
|
||||||||||||
Effect of dilutive stock options (thousands of shares) (1)
|
–
|
9,452
|
–
|
5,447
|
||||||||||||
Weighted average common shares outstanding
– diluted (thousands of shares) |
1,094,143
|
1,102,974
|
1,093,252
|
1,097,166
|
||||||||||||
Net earnings (loss)
|
$
|
(405
|
)
|
$
|
1,070
|
$
|
(657
|
)
|
$
|
1,692
|
||||||
Net earnings (loss) per common share – basic
|
$
|
(0.37
|
)
|
$
|
0.98
|
$
|
(0.60
|
)
|
$
|
1.55
|
||||||
– diluted
|
$
|
(0.37
|
)
|
$
|
0.97
|
$
|
(0.60
|
)
|
$
|
1.54
|
(1) | For the three months ended June 30, 2015 , the dilutive effect of 2,906,000 options has not been included in the determination of the weighted average number of common shares outstanding as the inclusion would be anti-dilutive to the net loss per common share (six months ended June 30, 2015 – 2,356,000). |
52
|
Canadian Natural Resources Limited
|
Jun 30, 2015
|
||||||||||||||||||||
Asset (liability)
|
Financial
assets at amortized
cost
|
Fair value
through profit
or loss
|
Derivatives
used for
hedging
|
Financial liabilities at amortized
cost
|
Total
|
|||||||||||||||
Accounts receivable
|
$
|
1,488
|
$
|
–
|
$
|
–
|
$
|
–
|
$
|
1,488
|
||||||||||
Other long-term assets
|
243
|
183
|
386
|
–
|
812
|
|||||||||||||||
Accounts payable
|
–
|
–
|
–
|
(543
|
)
|
(543
|
)
|
|||||||||||||
Accrued liabilities
|
–
|
–
|
–
|
(2,532
|
)
|
(2,532
|
)
|
|||||||||||||
Long-term debt (1)
|
–
|
–
|
–
|
(15,983
|
)
|
(15,983
|
)
|
|||||||||||||
$
|
1,731
|
$
|
183
|
$
|
386
|
$
|
(19,058
|
)
|
$
|
(16,758
|
)
|
Dec 31, 2014
|
||||||||||||||||||||
Asset (liability)
|
Financial
assets at
amortized
cost |
Fair value
through profit
or loss
|
Derivatives
used for
hedging
|
Financial
liabilities at amortized
cost |
Total
|
|||||||||||||||
Accounts receivable
|
$
|
1,889
|
$
|
–
|
$
|
–
|
$
|
–
|
$
|
1,889
|
||||||||||
Other long-term assets
|
120
|
415
|
184
|
–
|
719
|
|||||||||||||||
Accounts payable
|
–
|
–
|
–
|
(564
|
)
|
(564
|
)
|
|||||||||||||
Accrued liabilities
|
–
|
–
|
–
|
(3,279
|
)
|
(3,279
|
)
|
|||||||||||||
Other long-term liabilities
|
–
|
–
|
–
|
(40
|
)
|
(40
|
)
|
|||||||||||||
Long-term debt (1)
|
–
|
–
|
–
|
(14,002
|
)
|
(14,002
|
)
|
|||||||||||||
$
|
2,009
|
$ |
415
|
$
|
184
|
$
|
(17,885
|
)
|
$
|
(15,277
|
)
|
(1) | Includes the current portion of long-term debt. |
Jun 30, 2015
|
||||||||||||||||
Carrying amount
|
Fair value
|
|||||||||||||||
Asset (liability) (1) (2)
|
Level 1
|
Level 2
|
Level 3
|
|||||||||||||
Other long-term assets (3)
|
$
|
812
|
$
|
–
|
$
|
569
|
$
|
243
|
||||||||
Fixed rate long-term debt (4) (5)
|
$
|
(11,776
|
)
|
$
|
(12,483
|
)
|
$
|
–
|
$
|
–
|
Dec 31, 2014
|
||||||||||||||||
Carrying amount
|
Fair value
|
|||||||||||||||
Asset (liability) (1) (2)
|
Level 1
|
Level 2
|
Level 3
|
|||||||||||||
Other long-term assets (3)
|
$
|
719
|
$
|
–
|
$
|
599
|
$
|
120
|
||||||||
Fixed rate long-term debt (4) (5)
|
$
|
(11,018
|
)
|
$
|
(11,855
|
)
|
$
|
–
|
$
|
–
|
(1) | Excludes financial assets and liabilities where the carrying amount approximates fair value due to the liquid nature of the asset or liability (cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities). |
(2) | There were no transfers between Level 1, 2 and 3 financial instruments. |
(3) | The fair value of North West Redwater Partnership subordinated debt is based on the present value of future cash receipts. |
(4) | The fair value of fixed rate long-term debt has been determined based on quoted market prices. |
(5) | Includes the current portion of fixed rate long-term debt. |
Canadian Natural Resources Limited
|
53
|
Asset (liability)
|
Jun 30, 2015
|
Dec 31, 2014
|
||||||
Derivatives held for trading
|
||||||||
Crude oil price collars
|
$
|
177
|
$
|
410
|
||||
Crude oil WCS (1) differential swaps
|
–
|
(16
|
)
|
|||||
Foreign currency forward contracts
|
6
|
21
|
||||||
Cash flow hedges
|
||||||||
Foreign currency forward contracts
|
9
|
11
|
||||||
Cross currency swaps
|
377
|
173
|
||||||
$
|
569
|
$
|
599
|
|||||
Included within:
|
||||||||
Current portion of other long-term assets
|
$
|
308
|
$
|
436
|
||||
Other long-term assets
|
261
|
163
|
||||||
$
|
569
|
$
|
599
|
(1) | Western Canadian Select. |
Asset (liability)
|
Six Months Ended
Jun 30, 2015 |
Year Ended
Dec 31, 2014 |
||||||
Balance – beginning of period
|
$
|
599
|
$
|
(136
|
)
|
|||
Net change in fair value of outstanding derivative financial instruments
recognized in:
|
||||||||
Risk management activities
|
(229
|
)
|
451
|
|||||
Foreign exchange
|
255
|
270
|
||||||
Other comprehensive income (loss)
|
(56
|
)
|
14
|
|||||
Balance – end of period
|
569
|
599
|
||||||
Less: current portion
|
308
|
436
|
||||||
$
|
261
|
$
|
163
|
54
|
Canadian Natural Resources Limited
|
Three Months Ended
|
Six Months Ended
|
|||||||||||||||
Jun 30
2015 |
Jun 30
2014 |
Jun 30
2015 |
Jun 30
2014 |
|||||||||||||
Net realized risk management (gain) loss
|
$
|
(69
|
)
|
$
|
57
|
$
|
(325
|
)
|
$
|
(18
|
)
|
|||||
Net unrealized risk management loss
|
215
|
54
|
229
|
103
|
||||||||||||
$
|
146
|
$
|
111
|
$
|
(96
|
)
|
$
|
85
|
a) | Market risk |
Remaining term
|
Volume
|
Weighted average price
|
Index
|
|||||
Crude oil
|
||||||||
Price collars
|
Jul 2015
|
–
|
Dec 2015
|
50,000 bbl/d
|
US$80.00
|
–
|
US$120.52
|
Brent
|
Canadian Natural Resources Limited
|
55
|
Remaining term
|
Amount
|
Exchange rate
(US$/C$)
|
Interest rate
(US$)
|
Interest rate
(C$)
|
|||
Cross currency
|
|||||||
Swaps
|
Jul 2015
|
–
|
Mar 2016
|
US$500
|
1.109
|
Three-month
LIBOR plus
0.375%
|
Three-month
CDOR (1) plus
0.309%
|
Jul 2015
|
–
|
Aug 2016
|
US$250
|
1.116
|
6.00%
|
5.40%
|
|
Jul 2015
|
–
|
May 2017
|
US$1,100
|
1.170
|
5.70%
|
5.10%
|
|
Jul 2015
|
–
|
Nov 2021
|
US$500
|
1.022
|
3.45%
|
3.96%
|
|
Jul 2015
|
–
|
Mar 2038
|
US$550
|
1.170
|
6.25%
|
5.76%
|
(1) | Canadian Dealer Offered Rate (“CDOR”). |
b) | Credit risk |
c) | Liquidity risk |
56
|
Canadian Natural Resources Limited
|
Less than
1 year |
1 to less than
2 years |
2 to less than
5 years |
Thereafter
|
|||||||||||||
Accounts payable
|
$
|
543
|
$
|
–
|
$
|
–
|
$
|
–
|
||||||||
Accrued liabilities
|
$
|
2,532
|
$
|
–
|
$
|
–
|
$
|
–
|
||||||||
Long-term debt (1)
|
$
|
1,247
|
$
|
2,683
|
$
|
4,832
|
$
|
7,301
|
(1) | Long-term debt represents principal repayments only and does not reflect interest, original issue discounts and premiums or transaction costs. |
Remaining
2015
|
2016
|
2017
|
2018
|
2019
|
Thereafter
|
|||||||||||||||||||
Product transportation
and pipeline |
$
|
225
|
$
|
371
|
$
|
325
|
$
|
283
|
$
|
246
|
$
|
1,519
|
||||||||||||
Offshore equipment operating
leases and offshore drilling
|
$
|
214
|
$
|
136
|
$
|
84
|
$
|
64
|
$
|
20
|
$
|
–
|
||||||||||||
Office leases
|
$
|
21
|
$
|
42
|
$
|
45
|
$
|
46
|
$
|
48
|
$
|
293
|
||||||||||||
Other
|
$
|
85
|
$
|
111
|
$
|
24
|
$
|
34
|
$
|
1
|
$
|
–
|
Canadian Natural Resources Limited
|
57
|
Exploration and Production
|
||||||||||||||||||||||||||||||||||||||||||||||||
North America
|
North Sea
|
Offshore Africa
|
Total Exploration and Production
|
|||||||||||||||||||||||||||||||||||||||||||||
(millions of Canadian dollars,
unaudited) |
Three Months Ended
Jun 30 |
Six Months Ended
Jun 30 |
Three Months Ended
Jun 30 |
Six Months Ended
Jun 30 |
Three Months Ended
Jun 30 |
Six Months Ended
Jun 30 |
Three Months Ended
Jun 30 |
Six Months Ended
Jun 30 |
||||||||||||||||||||||||||||||||||||||||
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
2015
|
2014
|
|||||||||||||||||||||||||||||||||
Segmented product sales
|
2,645
|
4,463
|
4,979
|
8,120
|
201
|
226
|
353
|
424
|
111
|
172
|
178
|
196
|
2,957
|
4,861
|
5,510
|
8,740
|
||||||||||||||||||||||||||||||||
Less: royalties
|
(225
|
)
|
(659
|
)
|
(402
|
)
|
(1,175
|
)
|
(1
|
)
|
–
|
(1
|
)
|
(1
|
)
|
(5
|
)
|
(9
|
)
|
(8
|
)
|
(13
|
)
|
(231
|
)
|
(668
|
)
|
(411
|
)
|
(1,189
|
)
|
|||||||||||||||||
Segmented revenue
|
2,420
|
3,804
|
4,577
|
6,945
|
200
|
226
|
352
|
423
|
106
|
163
|
170
|
183
|
2,726
|
4,193
|
5,099
|
7,551
|
||||||||||||||||||||||||||||||||
Segmented expenses
|
||||||||||||||||||||||||||||||||||||||||||||||||
Production
|
645
|
752
|
1,396
|
1,415
|
161
|
143
|
295
|
266
|
55
|
81
|
70
|
88
|
861
|
976
|
1,761
|
1,769
|
||||||||||||||||||||||||||||||||
Transportation and blending
|
614
|
897
|
1,234
|
1,725
|
16
|
1
|
29
|
3
|
–
|
–
|
1
|
–
|
630
|
898
|
1,264
|
1,728
|
||||||||||||||||||||||||||||||||
Depletion, depreciation and amortization
|
1,020
|
1,006
|
2,124
|
1,822
|
99
|
65
|
186
|
123
|
39
|
28
|
61
|
33
|
1,158
|
1,099
|
2,371
|
1,978
|
||||||||||||||||||||||||||||||||
Asset retirement obligation accretion
|
24
|
26
|
47
|
48
|
10
|
10
|
19
|
19
|
2
|
3
|
5
|
5
|
36
|
39
|
71
|
72
|
||||||||||||||||||||||||||||||||
Realized risk management activities
|
(69
|
)
|
57
|
(325
|
)
|
(18
|
)
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
(69
|
)
|
57
|
(325
|
)
|
(18
|
)
|
||||||||||||||||||||||||||
Equity (gain) loss from investment
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
||||||||||||||||||||||||||||||||
Total segmented expenses
|
2,234
|
2,738
|
4,476
|
4,992
|
286
|
219
|
529
|
411
|
96
|
112
|
137
|
126
|
2,616
|
3,069
|
5,142
|
5,529
|
||||||||||||||||||||||||||||||||
Segmented earnings (loss) before the following
|
186
|
1,066
|
101
|
1,953
|
(86
|
)
|
7
|
(177
|
)
|
12
|
10
|
51
|
33
|
57
|
110
|
1,124
|
(43
|
)
|
2,022
|
|||||||||||||||||||||||||||||
Non-segmented expenses
|
||||||||||||||||||||||||||||||||||||||||||||||||
Administration
|
||||||||||||||||||||||||||||||||||||||||||||||||
Share-based compensation
|
||||||||||||||||||||||||||||||||||||||||||||||||
Interest and other financing expense
|
||||||||||||||||||||||||||||||||||||||||||||||||
Unrealized risk management activities
|
||||||||||||||||||||||||||||||||||||||||||||||||
Foreign exchange (gain) loss
|
||||||||||||||||||||||||||||||||||||||||||||||||
Total non-segmented expenses
|
||||||||||||||||||||||||||||||||||||||||||||||||
Earnings (loss) before taxes
|
||||||||||||||||||||||||||||||||||||||||||||||||
Current income tax (recovery) expense
|
||||||||||||||||||||||||||||||||||||||||||||||||
Deferred income tax expense
|
||||||||||||||||||||||||||||||||||||||||||||||||
Net earnings (loss)
|
58
|
Canadian Natural Resources Limited
|
Oil Sands Mining and Upgrading
|
Midstream
|
Inter-segment elimination and other
|
Total
|
|||||||||||||||||||||||||||||||||||||||||||||
(millions of Canadian dollars,
unaudited) |
Three Months Ended
Jun 30 |
Six Months Ended
Jun 30 |
Three Months Ended
Jun 30 |
Six Months Ended
Jun 30 |
Three Months Ended
Jun 30 |
Six Months Ended
Jun 30 |
Three Months Ended
Jun 30 |
Six Months Ended
Jun 30 |
||||||||||||||||||||||||||||||||||||||||
2015
|
2014 |
2015
|
2014 |
2015
|
2014 |
2015
|
2014 |
2015
|
2014 |
2015
|
2014 |
2015
|
2014 |
2015
|
2014 | |||||||||||||||||||||||||||||||||
Segmented product sales
|
689
|
1,241
|
1,349
|
2,323
|
35
|
30
|
70
|
61
|
(19
|
)
|
(19
|
)
|
(41
|
)
|
(43
|
)
|
3,662
|
6,113
|
6,888
|
11,081
|
||||||||||||||||||||||||||||
Less: royalties
|
(9
|
)
|
(74
|
)
|
(21
|
)
|
(125
|
)
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
(240
|
)
|
(742
|
)
|
(432
|
)
|
(1,314
|
)
|
||||||||||||||||||||||||
Segmented revenue
|
680
|
1,167
|
1,328
|
2,198
|
35
|
30
|
70
|
61
|
(19
|
)
|
(19
|
)
|
(41
|
)
|
(43
|
)
|
3,422
|
5,371
|
6,456
|
9,767
|
||||||||||||||||||||||||||||
Segmented expenses
|
||||||||||||||||||||||||||||||||||||||||||||||||
Production
|
321
|
404
|
667
|
816
|
9
|
10
|
18
|
19
|
(3
|
)
|
(2
|
)
|
(5
|
)
|
(5
|
)
|
1,188
|
1,388
|
2,441
|
2,599
|
||||||||||||||||||||||||||||
Transportation and blending
|
19
|
17
|
40
|
37
|
–
|
–
|
–
|
–
|
(20
|
)
|
(20
|
)
|
(40
|
)
|
(39
|
)
|
629
|
895
|
1,264
|
1,726
|
||||||||||||||||||||||||||||
Depletion, depreciation and amortization
|
119
|
135
|
258
|
265
|
3
|
3
|
6
|
5
|
–
|
–
|
–
|
–
|
1,280
|
1,237
|
2,635
|
2,248
|
||||||||||||||||||||||||||||||||
Asset retirement obligation accretion
|
7
|
11
|
15
|
23
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
43
|
50
|
86
|
95
|
||||||||||||||||||||||||||||||||
Realized risk management activities
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
–
|
(69
|
)
|
57
|
(325
|
)
|
(18
|
)
|
|||||||||||||||||||||||||||||
Equity (gain) loss from investment
|
–
|
–
|
–
|
–
|
(3
|
)
|
(3
|
)
|
12
|
(2
|
)
|
–
|
–
|
–
|
–
|
(3
|
)
|
(3
|
)
|
12
|
(2
|
)
|
||||||||||||||||||||||||||
Total segmented expenses
|
466
|
567
|
980
|
1,141
|
9
|
10
|
36
|
22
|
(23
|
)
|
(22
|
)
|
(45
|
)
|
(44
|
)
|
3,068
|
3,624
|
6,113
|
6,648
|
||||||||||||||||||||||||||||
Segmented earnings (loss) before the following
|
214
|
600
|
348
|
1,057
|
26
|
20
|
34
|
39
|
4
|
3
|
4
|
1
|
354
|
1,747
|
343
|
3,119
|
||||||||||||||||||||||||||||||||
Non-segmented expenses
|
||||||||||||||||||||||||||||||||||||||||||||||||
Administration
|
100
|
90
|
204
|
180
|
||||||||||||||||||||||||||||||||||||||||||||
Share-based compensation
|
(79
|
)
|
189
|
(15
|
)
|
332
|
||||||||||||||||||||||||||||||||||||||||||
Interest and other financing expense
|
85
|
92
|
171
|
160
|
||||||||||||||||||||||||||||||||||||||||||||
Unrealized risk management activities
|
215
|
54
|
229
|
103
|
||||||||||||||||||||||||||||||||||||||||||||
Foreign exchange (gain) loss
|
(87
|
)
|
(122
|
)
|
273
|
(5
|
)
|
|||||||||||||||||||||||||||||||||||||||||
Total non-segmented expenses
|
234
|
303
|
862
|
770
|
||||||||||||||||||||||||||||||||||||||||||||
Earnings (loss) before taxes
|
120
|
1,444
|
(519
|
)
|
2,349
|
|||||||||||||||||||||||||||||||||||||||||||
Current income tax (recovery) expense
|
(3
|
)
|
185
|
(108
|
)
|
311
|
||||||||||||||||||||||||||||||||||||||||||
Deferred income tax expense
|
528
|
189
|
246
|
346
|
||||||||||||||||||||||||||||||||||||||||||||
Net earnings (loss)
|
(405
|
)
|
1,070
|
(657
|
)
|
1,692
|
Canadian Natural Resources Limited
|
59
|
Six Months Ended
|
||||||||||||||||||||||||
Jun 30, 2015
|
Jun 30, 2014
|
|||||||||||||||||||||||
Net
expenditures
|
Non-cash
and fair value changes(2)
|
Capitalized
costs
|
Net
expenditures
|
Non-cash
and fair value changes(2)
|
Capitalized
costs
|
|||||||||||||||||||
Exploration and
evaluation assets
|
||||||||||||||||||||||||
Exploration and
Production
|
||||||||||||||||||||||||
North America
|
$
|
52
|
$
|
(160
|
)
|
$
|
(108
|
)
|
$
|
968
|
$
|
(84
|
)
|
$
|
884
|
|||||||||
North Sea
|
–
|
–
|
–
|
–
|
–
|
–
|
||||||||||||||||||
Offshore Africa
|
23
|
–
|
23
|
33
|
–
|
33
|
||||||||||||||||||
$
|
75
|
$
|
(160
|
)
|
$
|
(85
|
)
|
$
|
1,001
|
$
|
(84
|
)
|
$
|
917
|
||||||||||
Property, plant and
equipment
|
||||||||||||||||||||||||
Exploration and
Production
|
||||||||||||||||||||||||
North America
|
$
|
756
|
$
|
5
|
$
|
761
|
$
|
4,506
|
$
|
287
|
$
|
4,793
|
||||||||||||
North Sea
|
155
|
(2
|
)
|
153
|
195
|
–
|
195
|
|||||||||||||||||
Offshore Africa
|
258
|
–
|
258
|
11
|
–
|
11
|
||||||||||||||||||
1,169
|
3
|
1,172
|
4,712
|
287
|
4,999
|
|||||||||||||||||||
Oil Sands Mining and
Upgrading (3)
|
1,247
|
(49
|
)
|
1,198
|
1,403
|
(45
|
)
|
1,358
|
||||||||||||||||
Midstream
|
4
|
–
|
4
|
51
|
–
|
51
|
||||||||||||||||||
Head office
|
14
|
–
|
14
|
19
|
(1
|
)
|
18
|
|||||||||||||||||
$
|
2,434
|
$
|
(46
|
)
|
$
|
2,388
|
$
|
6,185
|
$
|
241
|
$
|
6,426
|
(1) | This table provides a reconciliation of capitalized costs including derecognitions and does not include the impact of foreign exchange adjustments. |
(2) | Asset retirement obligations, deferred income tax adjustments related to differences between carrying amounts and tax values, transfers of exploration and evaluation assets, and other fair value adjustments. |
(3) | Net expenditures for Oil Sands Mining and Upgrading also include capitalized interest and share-based compensation. |
Total Assets
|
||||||||
Jun 30
2015
|
Dec 31
2014 |
|||||||
Exploration and Production
|
||||||||
North America
|
$
|
33,177
|
$
|
34,382
|
||||
North Sea
|
2,845
|
2,711
|
||||||
Offshore Africa
|
1,606
|
1,214
|
||||||
Other
|
34
|
18
|
||||||
Oil Sands Mining and Upgrading
|
21,611
|
20,702
|
||||||
Midstream
|
1,144
|
1,048
|
||||||
Head office
|
126
|
125
|
||||||
$
|
60,543
|
$
|
60,200
|
60
|
Canadian Natural Resources Limited
|
Interest coverage ratios for the twelve month period ended June 30, 2015:
|
||||
Interest coverage (times)
|
||||
Net earnings (1)
|
5.0
|
x
|
||
Cash flow from operations (2)
|
14.7
|
x
|
(1) | Net earnings plus income taxes and interest expense excluding current and deferred PRT expense and other taxes; divided by the sum of interest expense and capitalized interest. |
(2) | Cash flow from operations plus current income taxes and interest expense excluding current PRT expense and other taxes; divided by the sum of interest expense and capitalized interest. |
Canadian Natural Resources Limited
|
61
|
Board of Directors
Catherine M. Best, FCA, ICD.D
N. Murray Edwards, O.C.
Timothy W. Faithfull
Honourable Gary A. Filmon, P.C., O.C., O.M.
Christopher L. Fong
Ambassador Gordon D. Giffin
Wilfred A. Gobert
Steve W. Laut
Honourable Frank J. McKenna, P.C., O.C., O.N.B., Q.C.
David A. Tuer
Annette Verschuren, O.C.
Officers
N. Murray Edwards
Chairman of the Board Steve W. Laut
President Tim S. McKay
Chief Operating Officer Douglas A. Proll
Executive Vice-President Lyle G. Stevens
Executive Vice-President, Canadian Conventional Corey B. Bieber
Chief Financial Officer and Senior Vice-President, Finance Réal M. Cusson
Senior Vice-President, Marketing Réal J.H. Doucet
Senior Vice-President, Horizon Projects Darren M. Fichter
Senior Vice-President, Exploitation Terry J. Jocksch
Senior Vice-President, Thermal Ronald K. Laing
Senior Vice-President, Corporate Development and Land Paul M. Mendes
Vice-President, Legal and General Counsel Bill R. Peterson
Senior Vice-President, Production and Development Operations Ken W. Stagg
Senior Vice-President, Exploration Scott G. Stauth
Senior Vice-President, North America Operations Betty Yee
Vice-President, Land Bruce E. McGrath
Corporate Secretary |
International Operations
CNR International (U.K.) Limited
Aberdeen, Scotland
W. David R. Bell
Vice-President, Exploration, International Barry Duncan
Vice-President, Finance, International Andrew M. McBoyle
Vice-President, Exploitation, International David B. Whitehouse
Vice-President, Development Operations, International Stock Listing
Toronto Stock Exchange
Trading Symbol – CNQ New York Stock Exchange
Trading Symbol – CNQ Registrar and Transfer Agent
Computershare Trust Company of Canada
Calgary, Alberta Toronto, Ontario Computershare Investor Services LLC
New York, New York Investor Relations
Telephone: (403) 514-7777
Email: ir@cnrl.com
|
62
|
Canadian Natural Resources Limited
|
Canadian Natural Resources Limited
|
63
|
C A N A D I A N N A T U R A L R E S O U R C E S L I M I T E D
2100, 855 - 2 Street S.W., Calgary, Alberta T2P 4J8
Telephone: (403) 517-6700 Facsimile: (403) 517-7350
Website: www.cnrl.com
Printed in Canada
|
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